UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☑ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 20172020
ORor
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-33303
TARGA RESOURCES PARTNERS LP
(Exact name of registrant as specified in its charter)
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(713) 584-1000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑.
As of October 31, 2017, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.
1
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or “the Partnership”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:
the timing and extent of changes in natural gas, natural gas liquids, crude oil and other commodity prices, interest rates and demand for our services;
the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and natural gas liquid supplies to our logistics and marketing facilities and our success in connecting our facilities to transportation services and markets;
our ability to access the capital markets, which will depend on general market conditions and the credit ratings for our debt obligations;
the amount of collateral required to be posted from time to time in our transactions;
our success in risk management activities, including the use of derivative instruments to hedge commodity price risks;
the level of creditworthiness of counterparties to various transactions with us;
changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;
weather and other natural phenomena;
industry changes, including the impact of consolidations and changes in competition;
our ability to obtain necessary licenses, permits and other approvals;
our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets;
general economic, market and business conditions; and
the risks described in our Annual Report on Form 10-K for the year ended December 31, 2016 (“Annual Report”) and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 (“Quarterly Report”) will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:
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PART I – FINANCIAL INFORMATION
TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS(Exact name of registrant as specified in its charter)
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| September 30, 2017 |
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| December 31, 2016 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
| $ | 103.9 |
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| $ | 68.0 |
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Trade receivables, net of allowances of $0.1 and $0.9 million at September 30, 2017 and December 31, 2016 |
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| 709.2 |
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| 673.2 |
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Inventories |
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| 267.4 |
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| 137.7 |
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Assets from risk management activities |
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| 18.7 |
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| 16.8 |
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Other current assets |
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| 80.5 |
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| 31.5 |
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Total current assets |
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| 1,179.7 |
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| 927.2 |
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Property, plant and equipment |
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| 13,685.2 |
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| 12,511.9 |
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Accumulated depreciation |
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| (3,616.4 | ) |
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| (2,821.0 | ) | ||||||||||
Property, plant and equipment, net |
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| 10,068.8 |
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| 9,690.9 |
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Intangible assets, net |
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| 2,214.8 |
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| 1,654.0 |
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Goodwill, net |
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| 256.6 |
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| 210.0 |
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Long-term assets from risk management activities |
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| 13.7 |
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| 5.1 |
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Investments in unconsolidated affiliates |
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| 222.1 |
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| 240.8 |
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Other long-term assets |
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| 16.5 |
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| 16.9 |
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Total assets |
| $ | 13,972.2 |
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| $ | 12,744.9 |
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LIABILITIES AND OWNERS' EQUITY |
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Current liabilities: |
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Accounts payable and accrued liabilities |
| $ | 949.2 |
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| $ | 773.9 |
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Accounts payable to Targa Resources Corp. |
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| 71.7 |
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| 61.0 |
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Liabilities from risk management activities |
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| 80.9 |
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| 49.1 |
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Current debt obligations |
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| 528.4 |
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| 275.0 |
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Total current liabilities |
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| 1,630.2 |
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| 1,159.0 |
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Long-term debt |
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| 3,933.6 |
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| 4,177.0 |
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Long-term liabilities from risk management activities |
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| 14.9 |
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| 26.1 |
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Deferred income taxes, net |
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| 26.9 |
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| 26.9 |
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Other long-term liabilities |
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| 484.9 |
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| 205.3 |
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Contingencies (see Note 16) |
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Owners' equity: |
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Series A preferred limited partners | Issued |
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| Outstanding |
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| 120.6 |
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| 120.6 |
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September 30, 2017 |
| 5,000,000 |
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| 5,000,000 |
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December 31, 2016 |
| 5,000,000 |
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| 5,000,000 |
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Common limited partners | Issued |
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| Outstanding |
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| 6,592.1 |
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| 5,939.9 |
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September 30, 2017 |
| 275,168,410 |
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| 275,168,410 |
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December 31, 2016 |
| 275,168,410 |
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| 275,168,410 |
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General partner | Issued |
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| Outstanding |
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| 810.1 |
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| 796.7 |
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September 30, 2017 |
| 5,629,136 |
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| 5,629,136 |
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December 31, 2016 |
| 5,629,136 |
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| 5,629,136 |
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Accumulated other comprehensive income (loss) |
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| (70.1 | ) |
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| (61.8 | ) | |||||||
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| 7,452.7 |
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| 6,795.4 |
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Noncontrolling interests in subsidiaries |
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| 429.0 |
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| 355.2 |
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Total owners' equity |
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| 7,881.7 |
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| 7,150.6 |
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Total liabilities and owners' equity |
| $ | 13,972.2 |
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| $ | 12,744.9 | �� | ||||||||||
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See notes to consolidated financial statements. |
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Delaware | 65-1295427 | |||
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||
811 Louisiana St, Suite 2100, Houston, Texas | 77002 | |||
(Address of principal executive offices) | (Zip Code) |
(713) 584-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol(s) | Name of exchange on which registered | ||
9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | NGLS/PA | New York Stock Exchange |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | ☐ | Accelerated filer | ☐ | ||
Non-accelerated filer | ☑ | Smaller reporting company | ☐ | ||
Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes☐ No☑
As of November 2, 2020, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.
1
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or the “Partnership”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:
• | the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and natural gas liquid supplies to our logistics and transportation facilities and our success in connecting our facilities to transportation services and markets; |
• | the timing and extent of changes in natural gas, natural gas liquids, crude oil and other commodity prices, interest rates and demand for our services; |
• | our ability to access the capital markets, which will depend on general market conditions, the credit ratings for our debt obligations and demand for our senior notes; |
• | the impact of outbreaks of illnesses, pandemics (like COVID-19) or any other public health crises; |
• | the amount of collateral required to be posted from time to time in our transactions; |
• | our success in risk management activities, including the use of derivative instruments to hedge commodity price risks; |
• | the level of creditworthiness of counterparties to various transactions with us; |
• | changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment; |
• | weather and other natural phenomena; |
• | industry changes, including the impact of consolidations and changes in competition; |
• | our ability to timely obtain and maintain necessary licenses, permits and other approvals; |
• | our ability to grow through internal growth capital projects or acquisitions and the successful integration and future performance of such assets; |
• | general economic, market and business conditions; and |
• | the risks described in our Annual Report on Form 10-K for the year ended December 31, 2019 (“Annual Report”) and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”). |
Additionally, while we have not been previously materially impacted by prior outbreaks of illnesses, pandemics or other public health crises, there are potential risks to us from the continued impact on global demand for commodities related to the COVID-19 pandemic. The COVID-19 pandemic reduced economic activity and the related demand for energy commodities, which contributed to weakened commodity prices compared to historical levels and price volatility during the nine months ended September 30, 2020 and is expected to continue to impact demand over the short-to-medium term.
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Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 (“Quarterly Report”) will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:
Bbl | Barrels (equal to 42 U.S. gallons) |
BBtu | Billion British thermal units |
Bcf | Billion cubic feet |
Btu | British thermal units, a measure of heating value |
/d | Per day |
GAAP | Accounting principles generally accepted in the United States of America |
gal | U.S. gallons |
LIBOR | London Interbank Offered Rate |
LPG | Liquefied petroleum gas |
MBbl | Thousand barrels |
MMBbl | Million barrels |
MMBtu | Million British thermal units |
MMcf | Million cubic feet |
MMgal | Million U.S. gallons |
NGL(s) | Natural gas liquid(s) |
NYMEX | New York Mercantile Exchange |
NYSE | New York Stock Exchange |
SCOOP | South Central Oklahoma Oil Province |
STACK | Sooner Trend, Anadarko, Canadian and Kingfisher |
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements.
TARGA RESOURCES PARTNERS LP
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| September 30, 2020 |
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| December 31, 2019 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
| $ | 248.0 |
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| $ | 291.1 |
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Trade receivables, net of allowances of $0.1 and $0.0 million at September 30, 2020 and December 31, 2019 |
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| 609.8 |
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| 855.2 |
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Inventories |
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| 261.7 |
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| 161.5 |
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Assets from risk management activities |
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| 88.9 |
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| 103.3 |
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Deposits |
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| 110.1 |
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| 35.4 |
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Held for sale assets |
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| 62.2 |
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| 137.7 |
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Other current assets |
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| 18.7 |
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| 18.8 |
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Total current assets |
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| 1,399.4 |
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| 1,603.0 |
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Property, plant and equipment, net |
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| 12,292.9 |
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| 14,549.0 |
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Intangible assets, net |
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| 1,417.6 |
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| 1,735.0 |
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Long-term assets from risk management activities |
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| 79.5 |
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| 35.5 |
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Investments in unconsolidated affiliates |
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| 718.8 |
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| 738.7 |
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Other long-term assets |
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| 86.4 |
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| 83.3 |
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Total assets |
| $ | 15,994.6 |
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| $ | 18,744.5 |
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LIABILITIES AND OWNERS' EQUITY |
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Current liabilities: |
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Accounts payable |
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| 617.2 |
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| $ | 952.9 |
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Accrued liabilities |
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| 40.3 |
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| 50.7 |
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Dividends payable |
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| 96.5 |
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| 92.7 |
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Interest payable |
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| 95.3 |
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| 125.4 |
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Accrued taxes |
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| 85.1 |
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| 62.0 |
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Accounts payable to Targa Resources Corp. |
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| 195.9 |
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| 193.8 |
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Liabilities from risk management activities |
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| 121.1 |
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| 104.1 |
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Current debt obligations |
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| 261.9 |
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| 382.2 |
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Held for sale liabilities |
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| 3.6 |
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| 6.4 |
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Total current liabilities |
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| 1,516.9 |
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| 1,970.2 |
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Long-term debt |
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| 7,217.2 |
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| 7,005.2 |
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Long-term liabilities from risk management activities |
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| 62.9 |
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| 40.8 |
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Deferred income taxes, net |
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| 23.0 |
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| 23.0 |
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Other long-term liabilities |
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| 261.3 |
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| 260.0 |
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Contingencies (see Note 11) |
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Owners' equity: |
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Series A preferred limited partners | Issued |
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| Outstanding |
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| 120.6 |
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| 120.6 |
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September 30, 2020 |
| 5,000,000 |
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| 5,000,000 |
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December 31, 2019 |
| 5,000,000 |
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| 5,000,000 |
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Common limited partners | Issued |
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| Outstanding |
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| 2,921.3 |
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| 5,022.7 |
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September 30, 2020 |
| 275,168,410 |
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| 275,168,410 |
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December 31, 2019 |
| 275,168,410 |
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| 275,168,410 |
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General partner | Issued |
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| Outstanding |
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| 735.0 |
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| 778.0 |
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September 30, 2020 |
| 5,629,136 |
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| 5,629,136 |
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December 31, 2019 |
| 5,629,136 |
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| 5,629,136 |
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Accumulated other comprehensive income (loss) |
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| (119.5 | ) |
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| 122.5 |
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| 3,657.4 |
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| 6,043.8 |
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Noncontrolling interests |
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| 3,255.9 |
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| 3,401.5 |
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Total owners' equity |
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| 6,913.3 |
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| 9,445.3 |
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Total liabilities and owners' equity |
| $ | 15,994.6 |
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| $ | 18,744.5 |
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See notes to consolidated financial statements. |
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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
| Three Months Ended September 30, |
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| Nine Months Ended September 30, |
| Three Months Ended September 30, |
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| Nine Months Ended September 30, |
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| 2017 |
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| 2016 |
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| 2017 |
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| 2016 |
| 2020 |
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| 2019 |
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| 2020 |
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| 2019 |
| ||||||||
| (Unaudited) |
| (Unaudited) |
| ||||||||||||||||||||||||||
| (In millions) |
| (In millions) |
| ||||||||||||||||||||||||||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities | $ | 1,871.5 |
|
| $ | 1,398.7 |
|
| $ | 5,353.1 |
|
| $ | 3,882.9 |
| $ | 1,840.8 |
|
| $ | 1,594.2 |
|
| $ | 4,900.8 |
|
| $ | 5,254.8 |
|
Fees from midstream services |
| 260.3 |
|
|
| 253.6 |
|
|
| 759.0 |
|
|
| 795.5 |
|
| 274.3 |
|
|
| 308.3 |
|
|
| 786.7 |
|
|
| 942.4 |
|
Total revenues |
| 2,131.8 |
|
|
| 1,652.3 |
|
|
| 6,112.1 |
|
|
| 4,678.4 |
|
| 2,115.1 |
|
|
| 1,902.5 |
|
|
| 5,687.5 |
|
|
| 6,197.2 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases |
| 1,663.1 |
|
|
| 1,222.7 |
|
|
| 4,737.8 |
|
|
| 3,378.9 |
|
| 1,303.2 |
|
|
| 1,328.1 |
|
|
| 3,346.8 |
|
|
| 4,415.7 |
|
Operating expenses |
| 155.5 |
|
|
| 143.0 |
|
|
| 462.6 |
|
|
| 413.9 |
|
| 181.9 |
|
|
| 200.2 |
|
|
| 565.1 |
|
|
| 600.7 |
|
Depreciation and amortization expense |
| 208.3 |
|
|
| 184.0 |
|
|
| 602.8 |
|
|
| 563.6 |
|
| 203.7 |
|
|
| 244.3 |
|
|
| 647.3 |
|
|
| 718.9 |
|
General and administrative expense |
| 46.6 |
|
|
| 44.0 |
|
|
| 139.4 |
|
|
| 132.3 |
|
| 56.3 |
|
|
| 65.6 |
|
|
| 171.7 |
|
|
| 212.3 |
|
Impairment of property, plant and equipment |
| 378.0 |
|
|
| — |
|
|
| 378.0 |
|
|
| — |
| |||||||||||||||
Impairment of goodwill |
| — |
|
|
| — |
|
|
| — |
|
|
| 24.0 |
| |||||||||||||||
Impairment of long-lived assets |
| 0 |
|
|
| 0 |
|
|
| 2,442.8 |
|
|
| 0 |
| |||||||||||||||
Other operating (income) expense |
| 0.6 |
|
|
| 4.9 |
|
|
| 17.2 |
|
|
| 6.1 |
|
| 72.2 |
|
|
| 18.4 |
|
|
| 73.8 |
|
|
| 21.7 |
|
Income (loss) from operations |
| (320.3 | ) |
|
| 53.7 |
|
|
| (225.7 | ) |
|
| 159.6 |
|
| 297.8 |
|
|
| 45.9 |
|
|
| (1,560.0 | ) |
|
| 227.9 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
| (51.9 | ) |
|
| (57.9 | ) |
|
| (169.5 | ) |
|
| (171.2 | ) |
| (94.9 | ) |
|
| (84.2 | ) |
|
| (283.0 | ) |
|
| (229.2 | ) |
Equity earnings (loss) |
| 0.2 |
|
|
| (2.2 | ) |
|
| (16.6 | ) |
|
| (11.4 | ) |
| 18.6 |
|
|
| 10.0 |
|
|
| 54.1 |
|
|
| 15.9 |
|
Gain (loss) from financing activities |
| — |
|
|
| — |
|
|
| (10.7 | ) |
|
| 21.4 |
|
| (13.7 | ) |
|
| 0 |
|
|
| 47.4 |
|
|
| (1.4 | ) |
Gain (loss) from sale of equity-method investment |
| 0 |
|
|
| 65.8 |
|
|
| 0 |
|
|
| 65.8 |
| |||||||||||||||
Change in contingent considerations |
| 126.8 |
|
|
| 0.3 |
|
|
| 125.6 |
|
|
| 0.3 |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| (8.8 | ) |
Other, net |
| 0.2 |
|
|
| 1.0 |
|
|
| (2.7 | ) |
|
| 0.8 |
|
| 1.3 |
|
|
| 0 |
|
|
| 2.0 |
|
|
| 0 |
|
Income (loss) before income taxes |
| (245.0 | ) |
|
| (5.1 | ) |
|
| (299.6 | ) |
|
| (0.5 | ) |
| 209.1 |
|
|
| 37.5 |
|
|
| (1,739.5 | ) |
|
| 70.2 |
|
Income tax (expense) benefit |
| — |
|
|
| (1.0 | ) |
|
| 4.2 |
|
|
| — |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
Net income (loss) |
| (245.0 | ) |
|
| (6.1 | ) |
|
| (295.4 | ) |
|
| (0.5 | ) |
| 209.1 |
|
|
| 37.5 |
|
|
| (1,739.5 | ) |
|
| 70.2 |
|
Less: Net income attributable to noncontrolling interests |
| 9.7 |
|
|
| 4.7 |
|
|
| 25.9 |
|
|
| 13.5 |
| |||||||||||||||
Less: Net income (loss) attributable to noncontrolling interests |
| 100.1 |
|
|
| 76.6 |
|
|
| 108.1 |
|
|
| 144.3 |
| |||||||||||||||
Net income (loss) attributable to Targa Resources Partners LP | $ | (254.7 | ) |
| $ | (10.8 | ) |
| $ | (321.3 | ) |
| $ | (14.0 | ) | $ | 109.0 |
|
| $ | (39.1 | ) |
| $ | (1,847.6 | ) |
| $ | (74.1 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to preferred limited partners | $ | 2.8 |
|
| $ | 2.8 |
|
| $ | 8.4 |
|
| $ | 8.4 |
| $ | 2.8 |
|
| $ | 2.8 |
|
| $ | 8.4 |
|
| $ | 8.4 |
|
Net income (loss) attributable to general partner |
| (5.2 | ) |
|
| 29.0 |
|
|
| (6.6 | ) |
|
| 68.2 |
|
| 2.1 |
|
|
| (0.9 | ) |
|
| (37.2 | ) |
|
| (1.7 | ) |
Net income (loss) attributable to common limited partners |
| (252.3 | ) |
|
| (42.6 | ) |
|
| (323.1 | ) |
|
| (90.6 | ) |
| 104.1 |
|
|
| (41.0 | ) |
|
| (1,818.8 | ) |
|
| (80.8 | ) |
Net income (loss) attributable to Targa Resources Partners LP | $ | (254.7 | ) |
| $ | (10.8 | ) |
| $ | (321.3 | ) |
| $ | (14.0 | ) | $ | 109.0 |
|
| $ | (39.1 | ) |
| $ | (1,847.6 | ) |
| $ | (74.1 | ) |
See notes to consolidated financial statements.
TARGA RESOURCESRESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||||
|
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||||
|
|
|
| (Unaudited) |
|
| (Unaudited) |
|
|
|
| (Unaudited) |
| |||||||||||||||||||||||
|
|
| (In millions) |
|
| (In millions) |
|
|
| (In millions) |
| |||||||||||||||||||||||||
Net income (loss) | Net income (loss) |
| $ | (245.0 | ) |
| $ | (6.1 | ) |
| $ | (295.4 | ) |
| $ | (0.5 | ) | Net income (loss) |
| $ | 209.1 |
|
| $ | 37.5 |
|
| $ | (1,739.5 | ) |
| $ | 70.2 |
| ||
Other comprehensive income (loss): | Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Commodity hedging contracts: | Commodity hedging contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Commodity hedging contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Change in fair value | Change in fair value |
|
| (106.8 | ) |
|
| 12.9 |
|
|
| (10.5 | ) |
|
| (40.5 | ) | Change in fair value |
|
| (128.7 | ) |
|
| 118.2 |
|
|
| (102.6 | ) |
|
| 167.8 |
| ||
Settlements reclassified to net income |
|
| 2.1 |
|
|
| (8.1 | ) |
|
| 2.2 |
|
|
| (50.6 | ) | ||||||||||||||||||||
Settlements reclassified to revenues | Settlements reclassified to revenues |
|
| (19.2 | ) |
|
| (41.5 | ) |
|
| (139.4 | ) |
|
| (106.1 | ) | |||||||||||||||||||
Other comprehensive income (loss) | Other comprehensive income (loss) |
|
| (104.7 | ) |
|
| 4.8 |
|
|
| (8.3 | ) |
|
| (91.1 | ) | Other comprehensive income (loss) |
|
| (147.9 | ) |
|
| 76.7 |
|
|
| (242.0 | ) |
|
| 61.7 |
| ||
Comprehensive income (loss) | Comprehensive income (loss) |
|
| (349.7 | ) |
|
| (1.3 | ) |
|
| (303.7 | ) |
|
| (91.6 | ) | Comprehensive income (loss) |
|
| 61.2 |
|
|
| 114.2 |
|
|
| (1,981.5 | ) |
|
| 131.9 |
| ||
Less: Comprehensive income attributable to noncontrolling interests |
|
| 9.7 |
|
|
| 4.7 |
|
|
| 25.9 |
|
|
| 13.5 |
| ||||||||||||||||||||
Less: Comprehensive income (loss) attributable to noncontrolling interests | Less: Comprehensive income (loss) attributable to noncontrolling interests |
|
| 100.1 |
|
|
| 76.6 |
|
|
| 108.1 |
|
|
| 144.3 |
| |||||||||||||||||||
Comprehensive income (loss) attributable to Targa Resources Partners LP | Comprehensive income (loss) attributable to Targa Resources Partners LP |
| $ | (359.4 | ) |
| $ | (6.0 | ) |
| $ | (329.6 | ) |
| $ | (105.1 | ) | Comprehensive income (loss) attributable to Targa Resources Partners LP |
| $ | (38.9 | ) |
| $ | 37.6 |
|
| $ | (2,089.6 | ) |
| $ | (12.4 | ) |
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| Limited |
|
| Limited |
|
| General |
|
| Other |
|
| Treasury |
|
| Non- |
|
|
|
|
| ||||||||||||||||||||||
|
| Partner |
|
| Partner |
|
| Partner |
|
| Comprehensive |
|
| Units |
|
| controlling |
|
|
|
|
| ||||||||||||||||||||||
|
| Preferred |
|
| Amount |
|
| Common |
|
| Amount |
|
| Units |
|
| Amount |
|
| Income (Loss) |
|
| Units |
|
| Amount |
|
| Interests |
|
| Total |
| |||||||||||
|
| (Unaudited) |
| |||||||||||||||||||||||||||||||||||||||||
|
| (In millions, except units in thousands) |
| |||||||||||||||||||||||||||||||||||||||||
Balance, December 31, 2016 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 5,939.9 |
|
|
| 5,629 |
|
| $ | 796.7 |
|
| $ | (61.8 | ) |
|
| — |
|
| $ | — |
|
| $ | 355.2 |
|
| $ | 7,150.6 |
|
Contributions from Targa Resources Corp. |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,587.5 |
|
|
| — |
|
|
| 32.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,620.0 |
|
Purchase of noncontrolling interests in subsidiary |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (12.5 | ) |
|
| (12.5 | ) |
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (33.4 | ) |
|
| (33.4 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 93.8 |
|
|
| 93.8 |
|
Other comprehensive income (loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (8.3 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (8.3 | ) |
Net income (loss) |
|
| — |
|
| 8.4 |
|
|
| — |
|
|
| (323.1 | ) |
|
| — |
|
|
| (6.6 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 25.9 |
|
|
| (295.4 | ) | |
Distributions |
|
| — |
|
|
| (8.4 | ) |
|
| — |
|
|
| (612.2 | ) |
|
| — |
|
|
| (12.5 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (633.1 | ) |
Balance, September 30, 2017 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 6,592.1 |
|
|
| 5,629 |
|
| $ | 810.1 |
|
| $ | (70.1 | ) |
|
| — |
|
| $ | — |
|
| $ | 429.0 |
|
| $ | 7,881.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
| |
|
| Limited |
|
| Limited |
|
| General |
|
| Other |
|
| Non- |
|
|
|
|
| |||||||||||||||||
|
| Partner |
|
| Partner |
|
| Partner |
|
| Comprehensive |
|
| controlling |
|
|
|
|
| |||||||||||||||||
|
| Preferred |
|
| Amount |
|
| Common |
|
| Amount |
|
| Units |
|
| Amount |
|
| Income (Loss) |
|
| Interests |
|
| Total |
| |||||||||
|
| (Unaudited) |
| |||||||||||||||||||||||||||||||||
|
| (In millions, except units in thousands) |
| |||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2020 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 2,865.2 |
|
|
| 5,629 |
|
| $ | 733.8 |
|
| $ | 28.4 |
|
| $ | 3,230.9 |
|
| $ | 6,978.9 |
|
Contributions from Targa Resources Corp. |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| (110.3 | ) |
|
| (110.3 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| 7.7 |
|
|
| 7.7 |
|
Non-cash allocation to noncontrolling interests |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 27.5 |
|
|
| 27.5 |
|
Other comprehensive income (loss) |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| (147.9 | ) |
|
| 0 |
|
|
| (147.9 | ) |
Net income (loss) |
|
| — |
|
|
| 2.8 |
|
|
| — |
|
|
| 104.1 |
|
|
| — |
|
|
| 2.1 |
|
|
| 0 |
|
|
| 100.1 |
|
|
| 209.1 |
|
Distributions |
|
| — |
|
|
| (2.8 | ) |
|
| — |
|
|
| (48.0 | ) |
|
| — |
|
|
| (0.9 | ) |
|
| 0 |
|
|
| 0 |
|
|
| (51.7 | ) |
Balance, September 30, 2020 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 2,921.3 |
|
|
| 5,629 |
|
| $ | 735.0 |
|
| $ | (119.5 | ) |
| $ | 3,255.9 |
|
| $ | 6,913.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
| |
|
| Limited |
|
| Limited |
|
| General |
|
| Other |
|
| Non- |
|
|
|
|
| |||||||||||||||||
|
| Partner |
|
| Partner |
|
| Partner |
|
| Comprehensive |
|
| controlling |
|
|
|
|
| |||||||||||||||||
|
| Preferred |
|
| Amount |
|
| Common |
|
| Amount |
|
| Units |
|
| Amount |
|
| Income (Loss) |
|
| Interests |
|
| Total |
| |||||||||
|
| (Unaudited) |
| |||||||||||||||||||||||||||||||||
|
| (In millions, except units in thousands) |
| |||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2019 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 5,703.1 |
|
|
| 5,629 |
|
| $ | 791.9 |
|
| $ | 109.9 |
|
| $ | 3,276.2 |
|
| $ | 10,001.7 |
|
Contributions from Targa Resources Corp. |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 9.8 |
|
|
| 0 |
|
|
| 0.2 |
|
|
| 0 |
|
|
| 0 |
|
|
| 10.0 |
|
Sale of ownership interests in subsidiaries |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| (87.2 | ) |
|
| (87.2 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| 115.3 |
|
|
| 115.3 |
|
Other comprehensive income (loss) |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 76.7 |
|
|
| 0 |
|
|
| 76.7 |
|
Net income (loss) |
|
| — |
|
|
| 2.8 |
|
|
| — |
|
|
| (41.0 | ) |
|
| — |
|
|
| (0.9 | ) |
|
| 0 |
|
|
| 76.6 |
|
|
| 37.5 |
|
Distributions |
|
| — |
|
|
| (2.8 | ) |
|
| — |
|
|
| (234.8 | ) |
|
| — |
|
|
| (4.8 | ) |
|
| 0 |
|
|
| 0 |
|
|
| (242.4 | ) |
Balance, September 30, 2019 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 5,437.1 |
|
|
| 5,629 |
|
| $ | 786.4 |
|
| $ | 186.6 |
|
| $ | 3,380.9 |
|
| $ | 9,911.6 |
|
See notes to consolidated financial statements.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
| |
|
| Limited |
|
| Limited |
|
| General |
|
| Other |
|
| Non- |
|
|
|
|
| |||||||||||||||||
|
| Partner |
|
| Partner |
|
| Partner |
|
| Comprehensive |
|
| controlling |
|
|
|
|
| |||||||||||||||||
|
| Preferred |
|
| Amount |
|
| Common |
|
| Amount |
|
| Units |
|
| Amount |
|
| Income (Loss) |
|
| Interests |
|
| Total |
| |||||||||
|
| (Unaudited) |
| |||||||||||||||||||||||||||||||||
|
| (In millions, except units in thousands) |
| |||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2019 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 5,022.7 |
|
|
| 5,629 |
|
| $ | 778.0 |
|
| $ | 122.5 |
|
| $ | 3,401.5 |
|
| $ | 9,445.3 |
|
Contributions from Targa Resources Corp. |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 49.0 |
|
|
| 0 |
|
|
| 1.0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 50.0 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| (314.5 | ) |
|
| (314.5 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| 33.3 |
|
|
| 33.3 |
|
Non-cash allocation to noncontrolling interests |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 27.5 |
|
|
| 27.5 |
|
Other comprehensive income (loss) |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| (242.0 | ) |
|
| 0 |
|
|
| (242.0 | ) |
Net income (loss) |
|
| — |
|
| 8.4 |
|
|
| — |
|
|
| (1,818.8 | ) |
|
| — |
|
|
| (37.2 | ) |
|
| 0 |
|
|
| 108.1 |
|
|
| (1,739.5 | ) | |
Distributions |
|
| — |
|
|
| (8.4 | ) |
|
| — |
|
|
| (331.6 | ) |
|
| — |
|
|
| (6.8 | ) |
|
| 0 |
|
|
| 0 |
|
|
| (346.8 | ) |
Balance, September 30, 2020 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 2,921.3 |
|
|
| 5,629 |
|
| $ | 735.0 |
|
| $ | (119.5 | ) |
| $ | 3,255.9 |
|
| $ | 6,913.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| Limited |
|
| Limited |
|
| General |
|
| Other |
| Treasury |
|
| Non- |
|
|
|
|
| |||||||||||||||||||||||
|
| Partner |
|
| Partner |
|
| Partner |
|
| Comprehensive |
|
| Units |
|
| controlling |
|
|
|
|
| ||||||||||||||||||||||
|
| Preferred |
|
| Amount |
|
| Common |
|
| Amount |
|
| Units |
|
| Amount |
|
| Income (Loss) |
|
| Units |
|
| Amount |
|
| Interests |
|
| Total |
| |||||||||||
|
| (Unaudited) |
| |||||||||||||||||||||||||||||||||||||||||
|
| (In millions, except units in thousands) |
| |||||||||||||||||||||||||||||||||||||||||
Balance, December 31, 2015 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 184,871 |
|
| $ | 4,550.4 |
|
|
| 3,773 |
|
| $ | 1,735.3 |
|
| $ | 86.8 |
|
|
| 212 |
|
| $ | (10.3 | ) |
| $ | 420.1 |
|
| $ | 6,902.9 |
|
Compensation on equity grants |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2.2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2.2 |
|
Distribution equivalent rights |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.2 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.2 | ) |
Issuance of common units under compensation program |
|
| — |
|
|
| — |
|
|
| 30 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Units tendered for tax withholding obligations |
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| (0.1 | ) |
|
| — |
|
|
| (0.1 | ) |
Cancellation of treasury units |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (10.2 | ) |
|
| — |
|
|
| (0.2 | ) |
|
| — |
|
|
| (213 | ) |
|
| 10.4 |
|
|
| — |
|
|
| — |
|
Contributions from Targa Resources Corp. |
|
| — |
|
|
| — |
|
|
| 58,621 |
|
|
| 1,167.2 |
|
|
| 1,197 |
|
|
| 23.8 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,191.0 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (16.8 | ) |
|
| (16.8 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 32.7 |
|
|
| 32.7 |
|
Other comprehensive income (loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (91.1 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (91.1 | ) |
Net income (loss) |
|
| — |
|
|
| 8.4 |
|
|
| — |
|
|
| (90.6 | ) |
|
| — |
|
|
| 68.2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 13.5 |
|
|
| (0.5 | ) |
Distributions |
|
| — |
|
|
| (8.4 | ) |
|
| — |
|
|
| (440.2 | ) |
|
| — |
|
|
| (94.0 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (542.6 | ) |
Balance, September 30, 2016 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 243,521 |
|
| $ | 5,178.6 |
|
|
| 4,970 |
|
| $ | 1,733.1 |
|
| $ | (4.3 | ) |
|
| — |
|
| $ | — |
|
| $ | 449.5 |
|
| $ | 7,477.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
| |
|
| Limited |
|
| Limited |
|
| General |
|
| Other |
|
| Non- |
|
|
|
|
| |||||||||||||||||
|
| Partner |
|
| Partner |
|
| Partner |
|
| Comprehensive |
|
| controlling |
|
|
|
|
| |||||||||||||||||
|
| Preferred |
|
| Amount |
|
| Common |
|
| Amount |
|
| Units |
|
| Amount |
|
| Income (Loss) |
|
| Interests |
|
| Total |
| |||||||||
|
| (Unaudited) |
| |||||||||||||||||||||||||||||||||
|
| (In millions, except units in thousands) |
| |||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2018 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 6,227.2 |
|
|
| 5,629 |
|
| $ | 802.6 |
|
| $ | 124.9 |
|
| $ | 1,270.8 |
|
| $ | 8,546.1 |
|
Contributions from Targa Resources Corp. |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 196.0 |
|
|
| 0 |
|
|
| 4.0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 200.0 |
|
Sale of ownership interests in subsidiaries |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| (10.5 | ) |
|
| — |
|
|
| (0.2 | ) |
|
| 0 |
|
|
| 1,619.7 |
|
|
| 1,609.0 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| (172.6 | ) |
|
| (172.6 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| 518.7 |
|
|
| 518.7 |
|
Other comprehensive income (loss) |
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 61.7 |
|
|
| 0 |
|
|
| 61.7 |
|
Net income (loss) |
|
| — |
|
|
| 8.4 |
|
|
| — |
|
|
| (80.8 | ) |
|
| — |
|
|
| (1.7 | ) |
|
| 0 |
|
|
| 144.3 |
|
|
| 70.2 |
|
Distributions |
|
| — |
|
|
| (8.4 | ) |
|
| — |
|
|
| (894.8 | ) |
|
| — |
|
|
| (18.3 | ) |
|
| 0 |
|
|
| 0 |
|
|
| (921.5 | ) |
Balance, September 30, 2019 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 275,168 |
|
| $ | 5,437.1 |
|
|
| 5,629 |
|
| $ | 786.4 |
|
| $ | 186.6 |
|
| $ | 3,380.9 |
|
| $ | 9,911.6 |
|
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| Nine Months Ended September 30, |
| |||||||||||||||||
|
|
| 2017 |
|
| 2016 |
|
|
| Nine Months Ended September 30, |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| 2020 |
|
| 2019 |
| |||
|
| (Unaudited) |
|
| (Unaudited) |
| ||||||||||||||
|
| (In millions) |
|
| (In millions) |
| ||||||||||||||
Cash flows from operating activities | Cash flows from operating activities |
|
|
|
|
|
|
|
| Cash flows from operating activities |
|
|
|
|
|
|
|
| ||
Net income (loss) | Net income (loss) |
| $ | (295.4 | ) |
| $ | (0.5 | ) | Net income (loss) |
| $ | (1,739.5 | ) |
| $ | 70.2 |
| ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
| ||
Amortization in interest expense | Amortization in interest expense |
|
| 7.1 |
|
|
| 9.8 |
| Amortization in interest expense |
|
| 7.6 |
|
|
| 6.8 |
| ||
Compensation on equity grants |
|
| — |
|
|
| 2.2 |
| ||||||||||||
Depreciation and amortization expense | Depreciation and amortization expense |
|
| 602.8 |
|
|
| 563.6 |
| Depreciation and amortization expense |
|
| 647.3 |
|
|
| 718.9 |
| ||
Impairment of property, plant and equipment |
|
| 378.0 |
|
|
| — |
| ||||||||||||
Impairment of goodwill |
|
| — |
|
|
| 24.0 |
| ||||||||||||
Impairment of long-lived assets | Impairment of long-lived assets |
|
| 2,442.8 |
|
|
| 0 |
| |||||||||||
Accretion of asset retirement obligations | Accretion of asset retirement obligations |
|
| 3.0 |
|
|
| 3.5 |
| Accretion of asset retirement obligations |
|
| 2.6 |
|
|
| 3.7 |
| ||
Increase (decrease) in redemption value of mandatorily redeemable preferred interests |
|
| 8.5 |
|
|
| (18.8 | ) | ||||||||||||
Equity (earnings) loss of unconsolidated affiliates | Equity (earnings) loss of unconsolidated affiliates |
|
| 16.6 |
|
|
| 11.4 |
| Equity (earnings) loss of unconsolidated affiliates |
|
| (54.1 | ) |
|
| (15.9 | ) | ||
Distributions of earnings received from unconsolidated affiliates | Distributions of earnings received from unconsolidated affiliates |
|
| 8.4 |
|
|
| 1.8 |
| Distributions of earnings received from unconsolidated affiliates |
|
| 65.5 |
|
|
| 26.0 |
| ||
Risk management activities | Risk management activities |
|
| 13.9 |
|
|
| 11.7 |
| Risk management activities |
|
| (214.2 | ) |
|
| 100.8 |
| ||
(Gain) loss on sale or disposition of assets |
|
| 16.6 |
|
|
| 5.7 |
| ||||||||||||
(Gain) loss on sale or disposition of business and assets | (Gain) loss on sale or disposition of business and assets |
|
| 58.0 |
|
|
| 3.6 |
| |||||||||||
Write-downs of assets |
|
|
| 13.5 |
|
|
| 17.9 |
| |||||||||||
(Gain) loss from financing activities | (Gain) loss from financing activities |
|
| 10.7 |
|
|
| (21.4 | ) | (Gain) loss from financing activities |
|
| (47.4 | ) |
|
| 1.4 |
| ||
Change in contingent considerations included in Other expense (income) |
|
| (125.6 | ) |
|
| (0.3 | ) | ||||||||||||
(Gain) loss from sale of equity-method investment |
|
|
| 0 |
|
|
| (65.8 | ) | |||||||||||
Change in contingent considerations | Change in contingent considerations |
|
| 0 |
|
|
| 8.8 |
| |||||||||||
Changes in operating assets and liabilities, net of business acquisitions: | Changes in operating assets and liabilities, net of business acquisitions: |
|
|
|
|
|
|
|
| Changes in operating assets and liabilities, net of business acquisitions: |
|
|
|
|
|
|
|
| ||
Receivables and other assets | Receivables and other assets |
|
| (91.5 | ) |
|
| (28.3 | ) | Receivables and other assets |
|
| 170.0 |
|
|
| 108.0 |
| ||
Inventories | Inventories |
|
| (136.4 | ) |
|
| (27.8 | ) | Inventories |
|
| (115.8 | ) |
|
| (89.7 | ) | ||
Accounts payable and other liabilities |
|
| 46.5 |
|
|
| 32.1 |
| ||||||||||||
Accounts payable, accrued liabilities and other liabilities | Accounts payable, accrued liabilities and other liabilities |
|
| (151.3 | ) |
|
| (9.5 | ) | |||||||||||
Interest payable | Interest payable |
|
| (30.1 | ) |
|
| 12.2 |
| |||||||||||
Net cash provided by operating activities | Net cash provided by operating activities |
|
| 463.2 |
|
|
| 568.7 |
| Net cash provided by operating activities |
|
| 1,054.9 |
|
|
| 897.4 |
| ||
Cash flows from investing activities | Cash flows from investing activities |
|
|
|
|
|
|
|
| Cash flows from investing activities |
|
|
|
|
|
|
|
| ||
Outlays for property, plant and equipment | Outlays for property, plant and equipment |
|
| (866.6 | ) |
|
| (425.0 | ) | Outlays for property, plant and equipment |
|
| (803.1 | ) |
|
| (2,433.8 | ) | ||
Outlays for business acquisition, net of cash acquired |
|
| (570.8 | ) |
|
| — |
| ||||||||||||
Proceeds from sale of business and assets | Proceeds from sale of business and assets |
|
| 135.9 |
|
|
| 2.7 |
| |||||||||||
Investments in unconsolidated affiliates | Investments in unconsolidated affiliates |
|
| (7.5 | ) |
|
| (4.6 | ) | Investments in unconsolidated affiliates |
|
| (2.2 | ) |
|
| (243.7 | ) | ||
Proceeds from sale of equity-method investment |
|
|
|
|
|
|
| 70.3 |
| |||||||||||
Return of capital from unconsolidated affiliates | Return of capital from unconsolidated affiliates |
|
| 2.2 |
|
|
| 3.4 |
| Return of capital from unconsolidated affiliates |
|
| 10.7 |
|
|
| 1.1 |
| ||
Other, net | Other, net |
|
| (14.8 | ) |
|
| 4.2 |
| Other, net |
|
| 4.7 |
|
|
| (16.3 | ) | ||
Net cash used in investing activities | Net cash used in investing activities |
|
| (1,457.5 | ) |
|
| (422.0 | ) | Net cash used in investing activities |
|
| (654.0 | ) |
|
| (2,619.7 | ) | ||
Cash flows from financing activities | Cash flows from financing activities |
|
|
|
|
|
|
|
| Cash flows from financing activities |
|
|
|
|
|
|
|
| ||
Debt obligations: | Debt obligations: |
|
|
|
|
|
|
|
| Debt obligations: |
|
|
|
|
|
|
|
| ||
Proceeds from borrowings under credit facility | Proceeds from borrowings under credit facility |
|
| 1,496.0 |
|
|
| 1,110.0 |
| Proceeds from borrowings under credit facility |
|
| 1,460.0 |
|
|
| 2,180.0 |
| ||
Repayments of credit facility | Repayments of credit facility |
|
| (1,216.0 | ) |
|
| (1,390.0 | ) | Repayments of credit facility |
|
| (1,360.0 | ) |
|
| (2,050.0 | ) | ||
Proceeds from borrowings under accounts receivable securitization facility | Proceeds from borrowings under accounts receivable securitization facility |
|
| 281.6 |
|
|
| 121.4 |
| Proceeds from borrowings under accounts receivable securitization facility |
|
| 476.4 |
|
|
| 770.0 |
| ||
Repayments of accounts receivable securitization facility | Repayments of accounts receivable securitization facility |
|
| (278.5 | ) |
|
| (115.7 | ) | Repayments of accounts receivable securitization facility |
|
| (596.4 | ) |
|
| (804.0 | ) | ||
Open market purchases of senior notes |
|
| — |
|
|
| (534.3 | ) | ||||||||||||
Proceeds from issuance of senior notes | Proceeds from issuance of senior notes |
|
| 1,000.0 |
|
|
| 1,500.0 |
| |||||||||||
Redemption of senior notes | Redemption of senior notes |
|
| (287.6 | ) |
|
| — |
| Redemption of senior notes |
|
| (831.0 | ) |
|
| (749.4 | ) | ||
Principal payments of finance leases | Principal payments of finance leases |
|
| (9.3 | ) |
|
| (8.5 | ) | |||||||||||
Costs incurred in connection with financing arrangements | Costs incurred in connection with financing arrangements |
|
| (0.1 | ) |
|
| (7.5 | ) | Costs incurred in connection with financing arrangements |
|
| (9.6 | ) |
|
| (25.1 | ) | ||
Repurchase of common units under compensation plans |
|
| — |
|
|
| (0.1 | ) | ||||||||||||
Purchase of noncontrolling interests in subsidiary |
|
| (12.5 | ) |
|
| — |
| ||||||||||||
Payment of contingent consideration | Payment of contingent consideration |
|
| 0 |
|
|
| (317.1 | ) | |||||||||||
Sale of ownership interests in subsidiaries | Sale of ownership interests in subsidiaries |
|
| 0 |
|
|
| 1,619.7 |
| |||||||||||
Contributions from general partner | Contributions from general partner |
|
| 32.5 |
|
|
| 23.8 |
| Contributions from general partner |
|
| 1.0 |
|
|
| 4.0 |
| ||
Contributions from TRC | Contributions from TRC |
|
| 1,587.5 |
|
|
| 1,167.2 |
| Contributions from TRC |
|
| 49.0 |
|
|
| 196.0 |
| ||
Contributions from noncontrolling interests | Contributions from noncontrolling interests |
|
| 93.8 |
|
|
| 32.7 |
| Contributions from noncontrolling interests |
|
| 33.3 |
|
|
| 518.7 |
| ||
Distributions to noncontrolling interests | Distributions to noncontrolling interests |
|
| (33.4 | ) |
|
| (16.8 | ) | Distributions to noncontrolling interests |
|
| (310.6 | ) |
|
| (98.9 | ) | ||
Distributions to unitholders | Distributions to unitholders |
|
| (633.1 | ) |
|
| (542.6 | ) | Distributions to unitholders |
|
| (346.8 | ) |
|
| (921.5 | ) | ||
Payments of distribution equivalent rights |
|
| — |
|
|
| (0.3 | ) | ||||||||||||
Net cash provided by (used in) financing activities | Net cash provided by (used in) financing activities |
|
| 1,030.2 |
|
|
| (152.2 | ) | Net cash provided by (used in) financing activities |
|
| (444.0 | ) |
|
| 1,813.9 |
| ||
Net change in cash and cash equivalents | Net change in cash and cash equivalents |
|
| 35.9 |
|
|
| (5.5 | ) | Net change in cash and cash equivalents |
|
| (43.1 | ) |
|
| 91.6 |
| ||
Cash and cash equivalents, beginning of period | Cash and cash equivalents, beginning of period |
|
| 68.0 |
|
|
| 135.4 |
| Cash and cash equivalents, beginning of period |
|
| 291.1 |
|
|
| 203.3 |
| ||
Cash and cash equivalents, end of period | Cash and cash equivalents, end of period |
| $ | 103.9 |
|
| $ | 129.9 |
| Cash and cash equivalents, end of period |
| $ | 248.0 |
|
| $ | 294.9 |
|
See notes to consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.
Note 1 — Organization and Operations
Our Organization
Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TRP,” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.
On February 17, 2016, TRC completed the previously announced transactions contemplated pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement,” and such transactions, the “TRC/TRP Merger”),
Our common units are wholly owned by and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”), TRC and Spartan Merger Sub LLC,no longer publicly traded as a subsidiaryresult of TRC (“Merger Sub”), pursuant to which TRC acquired indirectly allTRC’s acquisition of our outstanding common units that TRCit and its subsidiaries did not already own. Upon the terms and conditions set forthown in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.2016.
At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.
Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.“NGLS/PA.”
On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (the “Special GP Interest” as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.
Our Operations
We are primarily engaged in the business of:
gathering, compressing, treating, processing and selling natural gas;
• | gathering, compressing, treating, processing, transporting and purchasing and selling natural gas; |
storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;
• | transporting, storing, fractionating, treating and purchasing and selling NGLs and NGL products, including services to LPG exporters; and |
gathering, storing, terminaling and selling crude oil; and
storing, terminaling and selling refined petroleum products.
• | gathering, storing, terminaling and purchasing and selling crude oil. |
See Note 1915 – Segment Information for certain financial information regarding our business segments.
The employees supporting our operations are employed by Targa. Our consolidated financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services.
Note 2 — Basis of Presentation
We have prepared theseThe accompanying unaudited consolidated financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited consolidated financial statements and otherGAAP. Therefore, this information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto includedcontained in our Annual Report.
The unaudited consolidated financial statements for the three and nine months ended September 30, 2017 includeinformation furnished herein reflects all adjustments that we believe are, in the opinion of management, necessary for a fair statement of the results forof the interim periods.periods reported. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.
Our financial Operating results for the three and nine months ended September 30, 20172020 are not necessarily indicative of the results that may be expected for the full year.year ending December 31, 2020.
Note 3 — Significant Accounting Policies
Accounting Policy Updates
The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. ThereOther than the updates noted below, there were no significant updates or revisions to our accounting policies during the nine months ended September 30, 2017, except as noted below.2020.
Recent Accounting Pronouncements
Revenue from Contracts with Customers
Recently issued accounting pronouncements not yet adopted
Convertible Debt and Equity Instruments
In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of (1) identifying the contracts with customers, (2) identifying the performance obligations in the contracts, (3) determining the transaction price, (4) allocating the transaction price to the performance obligations, and (5) recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retrospectively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the standard is adopted.
In March 2016,2020, the FASB issued ASU 2016-08, Revenue from2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts with Customers (Topic 606)in Entity’s Own Equity (Subtopic 815-40): Principal versus Agent Considerations.Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The amendments in this update improvesimplify the operabilityaccounting for convertible debt instruments and understandabilityconvertible preferred stock by reducing the number of accounting models and embedded conversion features that can be recognized separately from the implementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer.primary contract. These amendments are effective for fiscal years,also enhance transparency and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.
In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.
In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition, and also provide additional practical expedients.
In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs.
We have disaggregated contracts within our two segments and are in the process of completing our review of contracts and transaction types with counterparties in order to evaluate how the new standard would impact our current revenue recognition and disclosure policies upon adoption.
Gathering and Processing Segment
Based on our progress to date, we have preliminarily concluded that the contracts within our Gathering and Processing segment where we purchase and obtain control of the entire natural gas stream are contracts with suppliers rather than customers and therefore, not included in the scope of Topic 606. However, these supplier contracts are subject to updated guidance in ASC 705, Cost of Sales and Services, whereby any embedded fees within such contracts, which historically have been reported as “Fees from midstream services,” will be reported instead as a reduction of “Product purchases” upon adoption of Topic 606. In addition, we have concluded that in most cases, we are acting as the principal in the sale of hydrocarbons to end customers. We are continuing to assess certain Gathering and Processing contracts whereby we obtain control over some, but not all, of the natural gas and natural gas liquids stream, including arrangements where the producer takes or may elect to take a portion of the merchantable gas and/or natural gas liquids in kind. Specifically, when such arrangements contain both a service revenue element and a supply element, we are in the process of determining how each element should be measured.
Logistics and Marketing Segment
At this time, we are not anticipating a significant change in revenue recognition for the contracts within our Logistics and Marketing segment, although the potential effects of contributions in aid of construction (which may also affect certain Gathering and Processing contracts where we are acting as an agent for the producer), tiered pricing, and excess fuel are currently being evaluated. We are also anticipating additionalimprove disclosures for fixed consideration allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the current reporting period, separate presentation of revenue from contracts with customersconvertible instruments and non-customer revenue (i.e. the effects of derivative activity and lease revenue) as well as unbilled receivables and deferred revenue.
The new revenue recognition standard is effective for us on January 1, 2018, and currently we plan to adopt using the modified retrospective method and will recognize a cumulative effect adjustment, if any, in the first quarter of 2018. However, we will continue to evaluate our planned adoption method based on our views regarding stakeholder needs and a final determination on remaining accounting matters still under evaluation. We have also established a cross-functional team to assist with the implementation through documentation of process changes, identification of implementation risks, update and development of mitigating controls, determination of data requirements, and identification of changes in system mapping and configuration.
Leases
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.
Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. These amendments change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments in this update affect investments in loans, investments in debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The amendments replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.
Cash Flow Classification
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). These amendments clarify how entities should classify certain cash receipts and cash payments in the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows.earnings per share guidance. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with
early adoption permitted. We plan to adopt the applicable amendments in the first quarter of 2018 and expect a minimal effect on our consolidated financial statements.
Recognition of Intra-Entity Transfers of Assets Other than Inventory
In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The amendments in this update are intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party or otherwise recovered, which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates the exception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis. The adoption resulted in no effect as TRP is not subject to income taxes.
Business Combinations
In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments clarify the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process are present. These amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted for transactions that have not been previously reported. We will apply this guidance to all transactions completed subsequent to our adoption of these amendments.
Impairment of Goodwill
In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which eliminates Step 2 from the goodwill impairment test. Step 2 required entities to compute the implied fair value of goodwill if it was determined that the carrying amount of a reporting unit exceeded its fair value. Under the amendments in this update, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. These amendments are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to apply these amendments for our annual goodwill impairment test as of November 30, 2017. Had we applied this new guidance for our November 2016 impairment test date, the full balance of our goodwill would have been impaired. We expect to apply these amendments for our annual goodwill impairment test as of November 30, which may result in impairment of goodwill for 2017.
Other Income
In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20), which clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Specifically, the amendments clarify that the guidance applies to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance financial asset" as an asset or group of assets for which substantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. These amendments also impact the accounting for partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset, but retains a noncontrolling ownership interest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017,2021, with early adoption permitted. This update permits the use of either the modified retrospective or full retrospective method of adoption. We are currently evaluating the effecteffects of such amendments on our consolidated financial statements.
Recently adopted accounting pronouncements
Stock Compensation – ScopeMeasurement of Modification AccountingCredit Losses
In May 2017,June 2016, the FASB issued ASU 2017-09, Compensation—Stock Compensation2016-13, Financial Instruments—Credit Losses (Topic 718)326): ScopeMeasurement of Modification Accounting, which clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. Under the new guidance, an entity will apply modification accounting only if the fair value, vesting conditions or the classification of the award changes as a result of the change in terms or conditions of a share-based payment award. In addition, the new guidance clarifies that regardless of whether an entity is required to apply modification accounting, the existing disclosure requirements and other aspects of GAAP associated with modifications continue to apply. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We early adopted the applicable amendments in the second quarter of 2017 and will apply the new guidance prospectively to any awards modifiedCredit Losses on or after the adoption date.
Financial Instruments with Down Round Features
In July 2017, FASB issued ASU 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception. The amendments in this update are intended to simplifymodify the accountingimpairment model for certain equity-linked financial instruments, including trade and embedded features with down round features thatother receivables, held-to-maturity debt securities and other instruments.
The amendments require entities to consider historical information, current conditions, and supportable forecasts to estimate expected credit losses, which may result in earlier recognition of losses. The amendments were effective for us on January 1, 2020 and were adopted by applying the strike price being reducedmodified retrospective transition approach. The adoption did not result in a cumulative effect adjustment to retained earnings on January 1, 2020. As a result of our adoption, see Accounting Policy Updates – Allowance for Doubtful Accounts below.
Accounting Policy Updates
Allowance for Doubtful Accounts
Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. We estimate the basisallowance for doubtful accounts through various procedures, including extensive review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts.
We continuously evaluate our ability to collect amounts owed to us. Receivables are considered past due if full payment is not received by the contractual due date. These procedures also include performing account reconciliations, dispute resolution and payment confirmation. We may involve our legal counsel to pursue the recovery of defaulted trade receivables.
As the financial condition of any counterparty changes, circumstances develop or additional information becomes available, adjustments to our allowance may be required.
Note 4 — Property, Plant and Equipment and Intangible Assets
|
| September 30, 2020 |
|
| December 31, 2019 |
|
| Estimated Useful Lives (In Years) | ||
Gathering systems |
| $ | 9,125.1 |
|
| $ | 8,976.8 |
|
| 5 to 20 |
Processing and fractionation facilities |
|
| 6,131.7 |
|
|
| 5,137.0 |
|
| 5 to 25 |
Terminaling and storage facilities |
|
| 1,514.8 |
|
|
| 1,495.5 |
|
| 5 to 25 |
Transportation assets |
|
| 2,422.6 |
|
|
| 2,292.4 |
|
| 10 to 50 |
Other property, plant and equipment |
|
| 123.7 |
|
|
| 183.9 |
|
| 3 to 50 |
Land |
|
| 160.7 |
|
|
| 159.7 |
|
| — |
Construction in progress |
|
| 697.8 |
|
|
| 1,576.5 |
|
| — |
Finance lease right-of-use assets |
|
| 51.3 |
|
|
| 48.8 |
|
|
|
Property, plant and equipment |
|
| 20,227.7 |
|
|
| 19,870.6 |
|
|
|
Accumulated depreciation, amortization and impairment |
|
| (7,934.8 | ) |
|
| (5,321.6 | ) |
|
|
Property, plant and equipment, net |
| $ | 12,292.9 |
|
| $ | 14,549.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets |
| $ | 2,643.5 |
|
| $ | 2,643.5 |
|
| 10 to 20 |
Accumulated amortization and impairment |
|
| (1,225.9 | ) |
|
| (908.5 | ) |
|
|
Intangible assets, net |
| $ | 1,417.6 |
|
| $ | 1,735.0 |
|
|
|
During the preparation of the pricing of future equity offerings. Under the new guidance, a down round feature will no longer need to be considered when determining whether certain financial instruments or embedded features should be classified as liabilities or equity instruments. That is, a down round feature will no longer preclude equity classification when assessing whether an instrument or embedded feature is indexed to an entity's own stock. In addition, the amendments clarify existing disclosure requirements for equity-classified instruments. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We early adopted the applicable amendments in the secondCompany's first quarter of 2017 on a retrospective basis noting no effect on our2019 consolidated financial statements.
Targeted Improvementsstatements, the Company identified an error related to Accountingdepreciation expense on certain assets that should have been placed in-service during 2018. The Company does not believe this error is material to its previously issued historical consolidated financial statements for Hedge Activities
In August 2017, FASB issued ASU 2017-12, Derivativesany of the periods impacted and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities, which are intended to better align risk management activities andaccordingly, has not adjusted the historical financial reporting for hedging relationships.statements. The new guidance covers multiple aspectsCompany recorded the cumulative impact of hedge accounting: (1) changes the way in which ineffectiveness is accounted, (2) allows for new hedge strategies, and (3) changes hedge disclosures. Under the new guidance, companies will have the option to perform a qualitative quarterly effectiveness assessment once the initial quantitative test has been performed. In addition, any ineffectiveness that exists is required to be recorded in other comprehensive income insteadone-time $12.5 million overstatement of in earnings as is required under current guidance. Several new hedging strategies will be allowed to be given hedge accounting treatment, most of which involve the hedging of contractually specified components. Lastly, disclosure requirements will be updated to (1) require that hedge income be presented on the same line item as the related hedged item, (2) require hedge program objectives to be disclosed, and (3) eliminate the requirement to separately disclose ineffectiveness. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We plan to adopt the applicable amendments indepreciation expense during the first quarter of 2018 and expect an immaterial effect on our consolidated financial statements.2019.
Note 4 – Acquisitions and Divestitures
2017 Acquisitions
Permian Acquisition
On March 1, 2017, Targa completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”).
We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the “initial purchase price”). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that would occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.
New Delaware’s gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties in Texas. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts,
with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity, and we are in the process of installing a 60 MMcf/d plant, known as the Oahu Plant, in the Delaware Basin with expectations of commencing operations in the fourth quarter of 2017. Currently, there is 40 MBbl/d of crude gathering capacity on the New Delaware system. Since March 1, 2017, financial and statistical data of New Delaware have been included in Sand Hills operations.
New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Midland system. Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations.
New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and the New Midland’s gas gathering and processing assets were connected to our existing WestTX system in October 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.
On January 26, 2017, Targa completed a public offering of 9,200,000 shares of its common stock (including the shares sold pursuant to the underwriters’ overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. Targa used the net proceeds from this public offering to fund the cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes.
The acquired businesses contributed revenues of $75.2 million and a net loss of $21.5 million to us for the period from March 1, 2017 to September 30, 2017, and are reported in our Gathering and Processing segment. As of September 30, 2017, we had incurred $5.6 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the nine months ended September 30, 2017.
Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations
The following summarized unaudited pro forma Consolidated Statement of Operations information for the nine months ended September 30, 2017 and September 30, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| Pro Forma |
|
| Pro Forma |
|
| Pro Forma |
|
| Pro Forma |
| ||||
Revenues |
| $ | 2,131.8 |
|
| $ | 1,663.0 |
|
| $ | 6,126.2 |
|
| $ | 4,697.3 |
|
Net income (loss) |
|
| (244.7 | ) |
|
| (18.3 | ) |
|
| (297.0 | ) |
|
| (44.7 | ) |
The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated:
Reflect the amortization expense resulting from the fair value of intangible assets recognized as part of the Permian Acquisition.
Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisition’s property, plant and equipment, net, and the fair value of property, plant and equipment acquired.
Exclude $5.6 million of acquisition-related costs incurred as of September 30, 2017 from pro forma net income for the nine months ended September 30, 2017. Pro forma net income for the nine months ended September 30, 2016 was adjusted to include those charges.
The following table summarizes the consideration transferred to acquire New Delaware and New Midland:
Fair Value of Consideration Transferred: |
|
|
|
|
Cash paid, net of $3.3 million cash acquired |
| $ | 570.8 |
|
Contingent consideration valuation as of the acquisition date |
|
| 416.3 |
|
Total |
| $ | 987.1 |
|
We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair value of the assets acquired and liabilities assumed at the acquisition date is shown below:
Fair value determination (final): |
| March 1, 2017 |
| |
Trade and other current receivables, net |
| $ | 6.7 |
|
Other current assets |
|
| 0.6 |
|
Property, plant and equipment |
|
| 255.8 |
|
Intangible assets |
|
| 692.3 |
|
Current liabilities |
|
| (14.1 | ) |
Other long-term liabilities |
|
| (0.8 | ) |
Total identifiable net assets |
|
| 940.5 |
|
Goodwill |
|
| 46.6 |
|
Total fair value of assets acquired and liabilities assumed |
| $ | 987.1 |
|
Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Such excess of purchase price over the fair value of net assets acquired was approximately $46.6 million, which was recorded as goodwill. The goodwill is attributable to expected operational and capital synergies. The goodwill is amortizable for tax purposes.
The fair value of assets acquired included trade receivables of $6.7 million, substantially all of which has been subsequently collected.
The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 17 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.
During the three months ended June 30, 2017, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs, including forecasts of future volumes, capital expenditures and operating expenses. The measurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the amounts recognized at that date. We recognized these measurement period adjustments in the three months ended June 30, 2017, with the effect in the Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at March 1, 2017. During the three months ended June 30, 2017, the acquisition date fair value of contingent consideration liability decreased by $45.3 million, intangible assets increased by $66.7 million, and other assets, net, increased by $0.4 million, which resulted in a decrease in goodwill of $112.4 million. These adjustments resulted in an increase in depreciation and amortization expense of $0.4 million recorded for the three months ended June 30, 2017.
During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional measurement period adjustments.
Contingent Consideration
A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that would occur in 2018 and 2019. The acquisition date fair value of the potential earn-out payments of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets. Changes in the fair value of this liability (that were not accounted for as revisions of the acquisition date fair value) are included in earnings. During the three and nine months ended September 30, 2017, we recognized $126.62020, depreciation expense was $168.5 million and $125.5$538.5 million, as Other incomerespectively. During the three and nine months ended September 30, 2019, depreciation expense was $201.4 million and $590.1 million, respectively.
Asset Impairments
We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of such assets may not be recoverable, and changes to our estimates could have an impact on our assessment of asset recoverability.
During the nine months ended September 30, 2020, global commodity prices declined due to factors that significantly impacted both demand and supply. As the COVID-19 pandemic spread, causing travel and other restrictions to be implemented globally, the demand for commodities declined. Additionally, the supply shock late in the first quarter from certain major oil producing nations increasing production also significantly contributed to the changesharp drop in commodity prices. While these major oil and gas producing countries subsequently agreed to collectively decrease production and global economies are beginning to re-open, these events, combined with the outbreak of the COVID-19 pandemic, contributed to volatility and depressed commodity prices. The drop in commodity prices resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production. Commodity prices remain weak relative to historical levels and have remained volatile as uncertainty around global commodity supply and demand continues due to the COVID-19 pandemic.
In the first quarter of 2020, we determined that indicators of impairment existed for certain asset groups reported primarily within our Gathering and Processing segment. For each asset group for which undiscounted future net cash flows were not sufficient to recover the net book value, fair value was determined through use of discounted estimated cash flows to measure the impairment loss.
The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the contingent consideration. Seecurrent environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs and the use of an appropriate discount rate. We believe our estimates and models used to determine fair value are similar to what a market participant would use.
Note 11 – Other Long-term Liabilities and Note 14 – Fair Value Measurements for additional discussion of the change inThe fair value measurement of our long-lived assets was based, in part, on significant inputs not observable in the market (as discussed above) and the fairthus represents a Level 3 measurement. The significant unobservable inputs used include discount rates and terminal value methodology.
Asexit multiples. We utilized a weighted average discount rate of September 30, 2017,14.0% when deriving the fair value of the asset groups impaired during the first potential earn-out paymentquarter of $5.9 million has been recorded as2020. The weighted average discount rate and exit multiples reflect management’s best estimate of inputs a component of Accounts payable and accrued liabilities, which are included within current liabilities on our Consolidated Balance Sheets. As of September 30, 2017, the fair value of the second potential earn-out payment of $284.9 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets.
Flag City Acquisition
On May 9, 2017, we purchased all of the equity interests in Flag City Processing Partners, LLC ("FCCP") from Boardwalk Midstream, LLC (“Boardwalk”) and all of the equity interests in FCPP Pipeline, LLC from Boardwalk Field Services, LLC (“BFS”) for a base purchase price of $60.0 million subject to customary closing adjustments. The final adjustment to the base purchase price paid to Boardwalk was an additional $3.6 million. As part of the acquisition (the “Flag City Acquisition”), we acquired a natural gas processing plant with 150 MMcf/d of operating capacity (the “Flag City Plant”) located in Jackson County, Texas; 24 miles of gas gathering pipeline systems and related rights-of-ways located in Bee and Karnes counties in Texas; 102.1 acres of land surrounding the Flag City Plant; and a limited number of gas supply contracts.
The gas processing activities under the Flag City Plant contracts have been transferred to our Silver Oak Plants. We have shut down the Flag City Plant and are moving the plant and its component parts to other Targa locations.
We accounted for this purchase as an asset acquisition and have capitalized less than $0.1 million of acquisition related costs as a component of the cost of assets acquired, which resulted in an allocation of $52.3 million of property, plant and equipment, $7.7 million of intangible assets for customer contracts and $3.6 million of current assets and liabilities, net.
Purchase of Outstanding Silver Oak II Interest
Effective as of June 1, 2017, we repurchased from SN Catarina, LLC (a subsidiary of Sanchez Energy Corp.) their 10% interest in our consolidated Silver Oak II Gas processing facility and other related assets located in Bee County, Texas for a purchase price of $12.5 million. The change in our ownership interest was accounted for as an equity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our Consolidated Statements of Operations as a result.
2017 Divestiture
Sale of Venice Gathering System, L.L.C.
Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer. VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. Targa Midstream Services LLC continued to operate the Venice gathering system for four months after closing pursuant to a Transition Services Agreement with VGS.
As a result of the April 4, 2017 sale, we recognized a loss of $16.1 million in our Consolidated Statements of Operations for the three months ended March 31, 2017 as part of Other operating (income) expense to impair our basis in the VGS net assets to its fair value.
2017 Joint Venture
Grand Prix Joint Venturemarket participant would utilize.
In May 2017, we announced plans to construct a new common carrier NGL pipeline. The NGL pipeline (“Grand Prix”) will transport volumes from the Permian Basin and our North Texas system to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported by our volumes and other third party customer commitments, and is expected to be in service in the secondfirst quarter of 2019. The capacity of the pipeline from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d.
In September 2017,2020, we sold to funds managed by Blackstone Energy Partners ("Blackstone") a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”).We are the operator and construction manager of Grand Prix. Our share of total growth capital expenditures for Grand Prix is expected to be approximately $975 million, with approximately $275 million of spending in 2017.
Concurrent with the sale of the minority interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement for transportation and fractionation whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin.
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
Commodities |
| $ | 255.6 |
|
| $ | 126.9 |
|
Materials and supplies |
|
| 11.8 |
|
|
| 10.8 |
|
|
| $ | 267.4 |
|
| $ | 137.7 |
|
Note 6 — Property, Plant and Equipment and Intangible Assets
|
| September 30, 2017 |
|
| December 31, 2016 |
|
| Estimated Useful Lives (In Years) | ||
Gathering systems |
| $ | 6,900.8 |
|
| $ | 6,626.9 |
|
| 5 to 20 |
Processing and fractionation facilities |
|
| 3,571.3 |
|
|
| 3,383.6 |
|
| 5 to 25 |
Terminaling and storage facilities |
|
| 1,238.0 |
|
|
| 1,205.0 |
|
| 5 to 25 |
Transportation assets |
|
| 343.2 |
|
|
| 451.4 |
|
| 10 to 25 |
Other property, plant and equipment |
|
| 284.7 |
|
|
| 274.0 |
|
| 3 to 25 |
Land |
|
| 123.8 |
|
|
| 121.2 |
|
| — |
Construction in progress |
|
| 1,223.4 |
|
|
| 449.8 |
|
| — |
Property, plant and equipment |
|
| 13,685.2 |
|
|
| 12,511.9 |
|
|
|
Accumulated depreciation |
|
| (3,616.4 | ) |
|
| (2,821.0 | ) |
|
|
Property, plant and equipment, net |
| $ | 10,068.8 |
|
| $ | 9,690.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets |
| $ | 2,736.6 |
|
| $ | 2,036.6 |
|
| 10 to 20 |
Accumulated amortization |
|
| (521.8 | ) |
|
| (382.6 | ) |
|
|
Intangible assets, net |
| $ | 2,214.8 |
|
| $ | 1,654.0 |
|
|
|
Impairment of North Texas Gathering and Processing Assets
We recorded a non-cash pre-tax impairment chargeimpairments of $378.0$2,442.8 million in the third quarter of 2017 forprimarily associated with the partial impairment of gas processing facilities and gathering systems associated with our North TexasMid-Continent operations and full impairment of our Coastal operations - all of which are in our Gathering and Processing segment. TheOur first quarter impairment is a result of our current assessment that forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Given the current price environment, Targa is projecting a continuingfurther decline in natural gas production across the Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins. We measured the impairmentMid-Continent and Gulf of property, plant and equipment using discounted estimated future cash flow analysis (“DCF”) including a terminal value (a Level 3 fair value measurement).Mexico. The future cash flows are based on our estimates of future revenues, income from operations and other factors, such as timing of capital expenditures. We take into account current and expected industry and market conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis is based on a weighted average cost of capital determined from relevant market comparisons. These carrying value adjustments are included in Impairment of property, plant and equipment expenselong-lived assets in our Consolidated Statements of Operations.There were no indicators of impairment identified during the second or third quarters of 2020.
Intangible Assets
Intangible assets consist of customer contracts and customer relationships acquired in the Permian and Flag City Acquisitions in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in 2012.prior business combinations. The fair valuesvalue of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering
system, pricing volatility and the discount rate. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers.
The intangible assets acquired
As a result of the triggering events and analysis described above, in the Permian Acquisitionfirst quarter of 2020, we recognized a non-cash pre-tax impairment loss associated with certain intangible customer relationships for which undiscounted future net cash flows were recorded at a fair value of $692.3 million. We are amortizing these intangible assets over a 15-year life usingnot sufficient to recover the straight-line method.
The intangible assets acquired in the Flag City Acquisition were recorded at a fair value of $7.7 million. We are amortizing these intangible assets over a 10-year life using the straight-line method.
The intangible assets acquired in the Atlas mergers are being amortized over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation over a 20-year life.net book value.
The estimated annual amortization expense for intangible assets is approximately $188.4$144.0 million, $182.6$130.9 million, $171.6$122.7 million, $159.4$117.5 million and $149.5$113.7 million for each of the years 20172020 through 2021.2024, respectively.
The changes in our intangible assets are as follows:
Balance at December 31, 2016 |
| $ | 1,654.0 |
|
Additions from Permian Acquisition |
|
| 692.3 |
|
Additions from Flag City Acquisition |
|
| 7.7 |
|
Amortization |
|
| (139.2 | ) |
Balance at September 30, 2017 |
| $ | 2,214.8 |
|
Balance at December 31, 2019 |
| $ | 1,735.0 |
|
Impairment |
|
| (208.6 | ) |
Amortization |
|
| (108.8 | ) |
Balance at September 30, 2020 |
| $ | 1,417.6 |
|
Note 7 – GoodwillAssets and Liabilities Held for Sale
In October 2020, we executed agreements to sell our assets in Channelview, Texas for approximately $58 million (the “October 2020 Sale”). As described in Noteof September 30, 2020, we classified our assets as held for sale and measured the fair value of the disposal group using the expected sales price under a contract with a third party (an input within Level 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. Duringof the first quarterfair value hierarchy). We recognized a loss of 2016, we finalized our 2015 impairment assessment and recorded additional impairment$58.3 million included within Other operating (income) expense of $24.0 million in our Consolidated StatementStatements of Operations. The impairment of goodwill was primarily dueOperations for the three and nine months ended September 30, 2020 to reduce the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas.
Changes in the net bookcarrying value of our goodwillassets to their recoverable amounts.
The sale closed in October 2020, and we used the proceeds for general corporate purposes. The sale of the assets is included in our Logistics and Transportation segment and does not qualify for reporting as a discontinued operation, as its divestiture did not represent a strategic shift that would have a major effect on our operations or financial results.
The adjusted carrying amounts of the assets and liabilities held for sale as of September 30, 2020 are as follows:
|
| WestTX |
|
| SouthTX |
|
| Permian |
|
| Total |
| ||||
Balance at December 31, 2016, net |
| $ | 174.7 |
|
| $ | 35.3 |
|
| $ | — |
|
| $ | 210.0 |
|
Permian Acquisition, March 1, 2017 |
|
| — |
|
|
| — |
|
|
| 46.6 |
|
|
| 46.6 |
|
Balance at September 30, 2017, net |
| $ | 174.7 |
|
| $ | 35.3 |
|
| $ | 46.6 |
|
| $ | 256.6 |
|
|
| September 30, 2020 |
| |
Current assets: |
|
|
|
|
Property, plant and equipment, net of accumulated depreciation and estimated loss on sale |
| $ | 61.0 |
|
Other current assets |
|
| 1.2 |
|
Total assets held for sale |
| $ | 62.2 |
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
Accounts payable and accrued liabilities |
| $ | 1.0 |
|
Other long-term obligations |
|
| 2.6 |
|
Total liabilities held for sale |
| $ | 3.6 |
|
Note 8 – Investments in Unconsolidated Affiliates
Our investments in unconsolidated affiliates consist of the following:5 — Debt Obligations
a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”);
three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: a 75% interest in T2 LaSalle, a gas gathering company; a 50% interest in T2 Eagle Ford, a gas gathering company; and a 50% interest in T2 EF Cogen (“Cogen”), which owns a cogeneration facility, (together the “T2 Joint Ventures”); and
a 50% operated ownership interest in Cayenne Pipeline, LLC (“Cayenne Joint Venture”).
The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting.
The T2 Joint Ventures were formed to provide services for the benefit of its joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with its joint interest owners, which cover costs of operations (excluding depreciation and amortization).
In July 2017, we entered into the Cayenne Joint Venture with American Midstream LLC to convert an existing 62-mile gas pipeline to an NGL pipeline connecting the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline
at Toca, Louisiana, for delivery to Enterprise’s Norco Fractionator. We acquired a 50% interest in the Cayenne Joint Venture for $5.0 million. The project is expected to be completed by November 2017.
The following table shows the activity related to our investments in unconsolidated affiliates:
|
| GCF |
|
| T2 LaSalle |
|
| T2 Eagle Ford |
|
| T2 EF Cogen |
|
| Cayenne |
|
| Total |
| ||||||
Balance at December 31, 2016 |
| $ | 46.1 |
|
| $ | 58.6 |
|
| $ | 118.6 |
|
| $ | 17.5 |
|
| $ | — |
|
| $ | 240.8 |
|
Equity earnings (loss) |
|
| 8.4 |
|
|
| (3.7 | ) |
|
| (7.9 | ) |
|
| (13.4 | ) |
|
| — |
|
|
| (16.6 | ) |
Cash distributions (1) |
|
| (10.6 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (10.6 | ) |
Acquisition |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 5.0 |
|
|
| 5.0 |
|
Contributions (2) |
|
| — |
|
|
| 0.4 |
|
|
| 1.2 |
|
|
| 0.1 |
|
|
| 1.8 |
|
|
| 3.5 |
|
Balance at September 30, 2017 |
| $ | 43.9 |
|
| $ | 55.3 |
|
| $ | 111.9 |
|
| $ | 4.2 |
|
| $ | 6.8 |
|
| $ | 222.1 |
|
|
| September 30, 2020 |
|
| December 31, 2019 |
| ||
Current: |
|
|
|
|
|
|
|
|
Accounts receivable securitization facility, due April 2021 (1) |
| $ | 250.0 |
|
| $ | 370.0 |
|
Finance lease liabilities |
|
| 11.9 |
|
|
| 12.2 |
|
Current debt obligations |
|
| 261.9 |
|
|
| 382.2 |
|
|
|
|
|
|
|
|
|
|
Long-term: |
|
|
|
|
|
|
|
|
Senior secured revolving credit facility, variable rate, due June 2023 (2) |
|
| 100.0 |
|
|
| — |
|
Senior unsecured notes: |
|
|
|
|
|
|
|
|
5¼% fixed rate, due May 2023 |
|
| 559.6 |
|
|
| 559.6 |
|
4¼% fixed rate, due November 2023 |
|
| 583.9 |
|
|
| 583.9 |
|
6¾% fixed rate, due March 2024 |
|
| — |
|
|
| 580.1 |
|
5⅛% fixed rate, due February 2025 |
|
| 481.0 |
|
|
| 500.0 |
|
5⅞% fixed rate, due April 2026 |
|
| 963.2 |
|
|
| 1,000.0 |
|
5⅜% fixed rate, due February 2027 |
|
| 468.1 |
|
|
| 500.0 |
|
6½% fixed rate, due July 2027 |
|
| 705.2 |
|
|
| 750.0 |
|
5% fixed rate, due January 2028 |
|
| 700.3 |
|
|
| 750.0 |
|
6⅞% fixed rate, due January 2029 |
|
| 679.3 |
|
|
| 750.0 |
|
5½% fixed rate, due March 2030 |
|
| 949.6 |
|
|
| 1,000.0 |
|
4⅞% fixed rate, due February 2031 |
|
| 1,000.0 |
|
|
| — |
|
TPL notes, 4¾% fixed rate, due November 2021 (3) |
|
| 6.5 |
|
|
| 6.5 |
|
TPL notes, 5⅞% fixed rate, due August 2023 (3) |
|
| 48.1 |
|
|
| 48.1 |
|
Unamortized premium |
|
| 0.2 |
|
|
| 0.3 |
|
|
|
| 7,245.0 |
|
|
| 7,028.5 |
|
Debt issuance costs, net of amortization |
|
| (48.5 | ) |
|
| (49.1 | ) |
Finance lease liabilities |
|
| 20.7 |
|
|
| 25.8 |
|
Long-term debt |
|
| 7,217.2 |
|
|
| 7,005.2 |
|
Total debt obligations |
| $ | 7,479.1 |
|
| $ | 7,387.4 |
|
Irrevocable standby letters of credit outstanding (2) |
| $ | 35.3 |
|
| $ | 88.2 |
|
|
|
(2) Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.
Our equity loss for the nine months ended September 30, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As a result of the decrease in current and expected future utilization of the underlying cogeneration assets, we have determined that factors indicate that a decrease in the value of our investment occurred that was other than temporary. As a result of this evaluation, we recorded an impairment loss of approximately $12.0 million in the first quarter of 2017, which represented our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as our impairment of the unamortized excess fair value resulting from the Atlas mergers.
The carrying values of the T2 Joint Ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of September 30, 2017, $26.8 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets.
Subsequent Event
Gulf Coast Express Joint Venture
In October 2017, we announced that we had executed a letter of intent along with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP with respect to the joint development of the proposed Gulf Coast Express Pipeline Project (“GCX Project”), which would provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. Under the terms of the letter of intent, we would own a 25% interest in the GCX Project. KMTP would serve as the operator and constructor of the GCX Project, and we would commit significant volumes to it, including certain volumes provided by Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin system. The participation of the three parties involved with GCX Project is subject to negotiation and execution of definitive agreements.
Note 9 — Accounts Payable and Accrued Liabilities
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
Commodities |
| $ | 600.9 |
|
| $ | 574.5 |
|
Other goods and services |
|
| 220.5 |
|
|
| 113.4 |
|
Interest |
|
| 48.7 |
|
|
| 52.2 |
|
Permian Acquisition contingent consideration, estimated current portion |
|
| 5.9 |
|
|
| — |
|
Income and other taxes |
|
| 57.3 |
|
|
| 19.1 |
|
Other |
|
| 15.9 |
|
|
| 14.7 |
|
|
| $ | 949.2 |
|
| $ | 773.9 |
|
Accounts payable and accrued liabilities includes $29.2 million and $30.2 million of liabilities to creditors to whom we have issued checks that remained outstanding as of September 30, 2017 and December 31, 2016. The estimated current portion of the Permian Acquisition contingent consideration represents the fair value as of September 30, 2017 of the first potential earn-out payment that would be payable in May 2018. The estimated remaining portion would be payable in May 2019 and is recorded within Other long-term liabilities on our Consolidated Balance Sheets.
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
|
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
Accounts receivable securitization facility, due December 2017 |
| $ | 278.1 |
|
| $ | 275.0 |
|
Senior unsecured notes, 5% fixed rate, due January 2018 (1) |
|
| 250.5 |
|
|
| — |
|
|
|
| 528.6 |
|
|
| 275.0 |
|
Debt issuance costs, net of amortization |
|
| (0.2 | ) |
|
| — |
|
Current debt obligations |
|
| 528.4 |
|
|
| 275.0 |
|
|
|
|
|
|
|
|
|
|
Long-term: |
|
|
|
|
|
|
|
|
Senior secured revolving credit facility, variable rate, due October 2020 (2) |
|
| 430.0 |
|
|
| 150.0 |
|
Senior unsecured notes: |
|
|
|
|
|
|
|
|
5% fixed rate, due January 2018 (1) |
|
| — |
|
|
| 250.5 |
|
4⅛% fixed rate, due November 2019 |
|
| 749.4 |
|
|
| 749.4 |
|
6⅜% fixed rate, due August 2022 |
|
| — |
|
|
| 278.7 |
|
5¼% fixed rate, due May 2023 |
|
| 559.6 |
|
|
| 559.6 |
|
4¼% fixed rate, due November 2023 |
|
| 583.9 |
|
|
| 583.9 |
|
6¾% fixed rate, due March 2024 |
|
| 580.1 |
|
|
| 580.1 |
|
5⅛% fixed rate, due February 2025 |
|
| 500.0 |
|
|
| 500.0 |
|
5⅜% fixed rate, due February 2027 |
|
| 500.0 |
|
|
| 500.0 |
|
TPL notes, 4¾% fixed rate, due November 2021 (3) |
|
| 6.5 |
|
|
| 6.5 |
|
TPL notes, 5⅞% fixed rate, due August 2023 (3) |
|
| 48.1 |
|
|
| 48.1 |
|
Unamortized premium |
|
| 0.4 |
|
|
| 0.5 |
|
|
|
| 3,958.0 |
|
|
| 4,207.3 |
|
Debt issuance costs, net of amortization |
|
| (24.4 | ) |
|
| (30.3 | ) |
Long-term debt |
|
| 3,933.6 |
|
|
| 4,177.0 |
|
Total debt obligations |
| $ | 4,462.0 |
|
| $ | 4,452.0 |
|
Irrevocable standby letters of credit outstanding |
| $ | 22.4 |
|
| $ | 13.2 |
|
(1) |
|
| As of September 30, |
(2) | As of September 30, 2020, availability under our |
| (3) | “TPL” refers to Targa Pipeline Partners |
The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the nine months ended September 30, 2017:
2020:
|
| Range of Interest Rates Incurred |
| Weighted Average Interest Rate Incurred |
| |
TRP Revolver |
|
|
|
|
| |
|
|
| 2.7% |
| 2.0% |
|
Compliance with Debt Covenants
As of September 30, 2017,2020, we were in compliance with the covenants contained in our various debt agreements.
Securitization FacilitySenior Unsecured Notes Issuance
On February 23, 2017,In August 2020, we amendedissued $1.0 billion aggregate principal amount of 4⅞% Senior Notes due 2031 (the “August 2020 Offering”), resulting in net proceeds of $991.0 million. The 4⅞% Senior Notes due 2031 have substantially similar terms and covenants as our other series of Senior Notes. A portion of the accounts receivable securitization facility (“Securitization Facility”net proceeds from the issuance were used to fund the concurrent cash tender offer (the “Tender Offer”) to increaseof our 6¾% Senior Notes due 2024 and redeem any 6¾% Senior Notes due 2024 that remained outstanding after consummation of the facility size from $275.0 million to $350.0 million. AsTender Offer, with the remainder used for repayment of September 30, 2017, there was $278.1 million outstandingborrowings under the Securitization Facility.TRP Revolver. See “Debt Extinguishments and Repurchases” for further details of the concurrent tender offer.
Debt Extinguishments and Repurchases & Extinguishments
In June 2017,Concurrent with the August 2020 Offering, we redeemedcommenced the Tender Offer to purchase for cash, subject to certain terms and conditions, any and all of our outstanding 6⅜6¾% Senior Notes due 2024. We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million.
Subsequent to the closing of the Tender Offer in August 2022 (“6⅜2020, we redeemed the 6¾% Senior Notes”), totaling $278.7Notes due 2024 for the remaining note balance of $318.0 million in aggregate principal amount, at(the “2024 Note Redemption”). As a priceresult of 103.188% plus accrued interest through the redemption date. The redemption resulted inTender Offer and the 2024 Note Redemption, we recorded a $10.7loss due to debt extinguishment of $13.7 million loss, which is reflected as Loss from financing activities in the Consolidated Statementscomprised of Operations, consisting of$11.1 million premiums paid of $8.9 million and a non-cash loss to write-off $1.8of $2.6 million of unamortized debt issuance costs.
Subsequent EventsDebt Repurchases
The following table summarizes our senior note repurchases for the nine months ended September 30, 2020:
Debt Repurchased |
| Book Value |
|
| Payment |
|
| Gain (Loss) |
|
| Write-off of Debt Issuance Costs |
|
| Net Gain |
| |||||
5⅛% Senior Notes due 2025 |
| $ | 19.0 |
|
| $ | (14.6 | ) |
| $ | 4.4 |
|
| $ | (0.1 | ) |
| $ | 4.3 |
|
5⅞% Senior Notes due 2026 |
|
| 36.8 |
|
|
| (29.7 | ) |
|
| 7.1 |
|
|
| (0.2 | ) |
|
| 6.9 |
|
5⅜% Senior Notes due 2027 |
|
| 31.9 |
|
|
| (26.6 | ) |
|
| 5.3 |
|
|
| (0.2 | ) |
|
| 5.1 |
|
6½% Senior Notes due 2027 |
|
| 44.8 |
|
|
| (35.5 | ) |
|
| 9.3 |
|
|
| (0.4 | ) |
|
| 8.9 |
|
5% Senior Notes due 2028 |
|
| 49.7 |
|
|
| (38.0 | ) |
|
| 11.7 |
|
|
| (0.4 | ) |
|
| 11.3 |
|
6⅞% Senior Notes due 2029 |
|
| 70.7 |
|
|
| (55.2 | ) |
|
| 15.5 |
|
|
| (0.6 | ) |
|
| 14.9 |
|
5½% Senior Notes due 2030 |
|
| 50.4 |
|
|
| (40.2 | ) |
|
| 10.2 |
|
|
| (0.5 | ) |
|
| 9.7 |
|
6¾% Senior Notes due 2024 |
|
| 580.1 |
|
|
| (591.2 | ) |
|
| (11.1 | ) |
|
| (2.6 | ) |
|
| (13.7 | ) |
|
| $ | 883.4 |
|
| $ | (831.0 | ) |
| $ | 52.4 |
|
| $ | (5.0 | ) |
| $ | 47.4 |
|
We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
In October 2017,Contractual Obligations
The following table summarizes payment obligations for debt instruments after giving effect to the debt repurchases detailed above:
|
| Payments Due By Period |
| |||||||||||||||||
|
|
|
|
|
| Less Than |
|
|
|
|
|
|
|
| More Than |
| ||||
|
| Total | 1 Year | 1-3 Years | 3-5 Years | 5 Years |
| |||||||||||||
|
| (in millions) |
| |||||||||||||||||
Long-term debt obligations (1) |
| $ | 7,244.8 |
|
| $ | - |
|
| $ | 714.2 |
|
| $ | 1,064.9 |
|
| $ | 5,465.7 |
|
Interest on debt obligations (2) |
|
| 2,729.3 |
|
|
| 402.0 |
|
|
| 791.0 |
|
|
| 657.6 |
|
|
| 878.7 |
|
|
| $ | 9,974.1 |
|
| $ | 402.0 |
|
| $ | 1,505.2 |
|
| $ | 1,722.5 |
|
| $ | 6,344.4 |
|
(1)Represents scheduled future maturities of consolidated debt obligations for the periods indicated.
(2)Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing September 30, 2020 rates for floating debt.
Subsequent Event
On November 2, 2020, we issued $750.0redeemed the $559.6 million aggregate principal amountremaining balance of 5% senior notes due January 2028 (the “5%our 5¼% Senior Notes due 2028”). We used the net proceeds of $744.4 million after costs from this offering to redeem our 5% Senior Notes due 2018, reduce borrowings under our credit facilities, and for general partnership purposes.2023.
In October 2017, we redeemed our outstanding 5% Senior Notes due 2018 at par value plus accrued interest through the redemption date. The redemption resulted in a non-cash Loss from financing activities to write-off $0.2 million of unamortized debt issuance costs in the fourth quarter of 2017.
Note 116 — Other Long-term Liabilities
Other long-term liabilities are comprised of the following obligations:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
Asset retirement obligations |
| $ | 49.4 |
|
| $ | 64.1 |
|
Mandatorily redeemable preferred interests |
|
| 80.0 |
|
|
| 68.5 |
|
Deferred revenue |
|
| 67.5 |
|
|
| 69.8 |
|
Permian Acquisition contingent consideration, noncurrent portion |
|
| 284.9 |
|
|
| — |
|
Other liabilities |
|
| 3.1 |
|
|
| 2.9 |
|
Total long-term liabilities |
| $ | 484.9 |
|
| $ | 205.3 |
|
Asset Retirement Obligations
Our ARO primarily relate to certain gas gathering pipelinesdeferred revenue, asset retirement obligations and processing facilities. The changes in our ARO are as follows:
Balance at December 31, 2016 |
| $ | 64.1 |
|
Additions (1) |
|
| 0.8 |
|
Reduction due to sale of VGS |
|
| (21.6 | ) |
Change in cash flow estimate |
|
| 3.1 |
|
Accretion expense |
|
| 3.0 |
|
Balance at September 30, 2017 |
| $ | 49.4 |
|
|
|
Mandatorily Redeemable Preferred Interests
Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.
For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Because redemption cannot occur before 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of September 30, 2017.
The following table shows the changes attributable to mandatorily redeemable preferred interests:
Balance at December 31, 2016 |
| $ | 68.5 |
|
Income attributable to mandatorily redeemable preferred interests |
|
| 3.0 |
|
Change in estimated redemption value included in interest expense |
|
| 8.5 |
|
Balance at September 30, 2017 |
| $ | 80.0 |
|
operating lease liabilities.
We have certain long-term contractual arrangements underfor which we have received consideration but which require future performance by Targa. These arrangements result inthat we are not yet able to recognize as revenue. The resulting deferred revenue which will be recognized over the periods that performance will be provided.once all conditions for revenue recognition have been met.
Deferred revenue as of September 30, 2020 and December 31, 2019, was $169.4 million and $172.0 million, respectively, which includes consideration$129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. OnIn December 27, 2015, Targa Terminals LLC and Noble Americas Corp., a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we will build and operate a crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 barrels of storage capacity. The Channelview Splitter will have the capability2018, Vitol elected to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be completed by the first half of 2018, and has an estimated total cost of approximately $140.0 million. The first annual advance payment due underterminate the Splitter Agreement was received in October 2016 and has been recorded as deferred revenue, as the Splitter Agreement requires future performance by Targa.Agreement. The Splitter Agreement provides that subsequentthe first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of $43.0 million (subjectrevenue recognition related to an annual inflation factor) are to be paid to Targa through 2022. In October 2017, we received $43.0 million representing the second annual payment under the Splitter Agreement which will be recorded as deferred revenue. The deferred revenue receipts will be recognized overis dependent on the contractual period that future performance will be provided, currently anticipated to commenceoutcome of current litigation with start-up in 2018 and continuing through 2025.
Vitol. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the gathering assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. Because the gas contract amendment will require future performance by Targa, we have recorded the consideration received as deferred revenue. The deferred revenue related to this amendment is being recognized on a straight-line basis through the end of the agreement’s term in 2030.
Deferred revenue also includesagreement and consideration received for other construction activities of facilities connected to our systems. The deferred revenueSee Part II—Item 1. Legal Proceedings for further details on the related to these other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023.litigation.
The following table shows the components of deferred revenue:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
Splitter agreement |
| $ | 43.0 |
|
| $ | 43.0 |
|
Gas contract amendment |
|
| 18.6 |
|
|
| 19.7 |
|
Other deferred revenue |
|
| 5.9 |
|
|
| 7.1 |
|
Total deferred revenue |
| $ | 67.5 |
|
| $ | 69.8 |
|
The following table shows the changes in deferred revenue:
Balance at December 31, 2016 |
| $ | 69.8 |
|
Additions |
|
| — |
|
Revenue recognized |
|
| (2.3 | ) |
Balance at September 30, 2017 |
| $ | 67.5 |
|
Contingent Consideration
Upon closing of the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fair value. The potential earn-out payments will be based upon a multiple of gross margin realized during the first two annual periods after the acquisition date from contracts that existed on March 1, 2017. The first potential earn-out payment would occur in May 2018 and the second potential earn-out payment would occur in May 2019. The preliminary acquisition date fair value of the contingent consideration of $461.6 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets as of March 31, 2017. Subsequent changes in the fair value of the contingent consideration that were not accounted for as revisions (measurement period adjustments) to the acquisition date fair value have been included in Other income (expense).
During the three months ended June 30, 2017, we recognized certain adjustments that were accounted for as revisions to the acquisition date fair value and decreased the acquisition date fair value of the contingent consideration by $45.3 million to $416.3
million. During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional revisions to the acquisition date fair value. See Note 4 – Acquisitions and Divestments for additional discussion.
For the period from the acquisition date to September 30, 2017, the fair value of this liability decreased by $125.5 million, bringing the total Permian Acquisition contingent consideration to $290.8 million at September 30, 2017. The decrease in fair value of the contingent consideration was primarily related to reductions in actual and forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date. Such changes in estimated fair value of the contingent consideration are attributable to events and circumstances that occurred after the acquisition date, and as such have been recognized in Other income (expense).
As of September 30, 2017, the fair value of the first potential earn-out payment of $5.9 million has been recorded as a component of Accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. As of September 30, 2017, the fair value of the second potential earn-out payment of $284.9 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. See Note 14 – Fair Value Measurements for additional discussion of the fair value methodology.
The following table shows the changes in contingent consideration:
Balance at March 1, 2017 (acquisition date) |
| $ | 461.6 |
|
Measurement period adjustment of acquisition date value |
|
| (45.3 | ) |
Decrease in fair value due to factors occurring after acquisition date |
|
| (125.5 | ) |
Balance at September 30, 2017 |
|
| 290.8 |
|
Less: Current portion |
|
| (5.9 | ) |
Long-term balance at September 30, 2017 |
| $ | 284.9 |
|
Note 127 — Partnership Units and Related Matters
Distributions
As a result of the TRC/TRP Merger,
TRC is entitled to receive all Partnership distributions from available cash on the Partnership’s common units after payment of preferred unitsunit distributions each quarter. We have discretion under the Third A&R Partnership Agreement as to whether to distribute all available cash for any period. See Note 1 – Organization and Operations.
The following table details the distributions declared orand paid by us for the nine months ended September 30, 2017:2020:
Three Months Ended |
| Date Paid Or to Be Paid |
| Total Distributions |
|
| Distributions to Targa Resources Corp. |
| ||
September 30, 2017 |
| November 10, 2017 | $ |
| 225.4 |
| $ |
| 222.6 |
|
June 30, 2017 |
| August 10, 2017 |
|
| 225.4 |
|
|
| 222.6 |
|
March 31, 2017 |
| May 11, 2017 |
|
| 209.6 |
|
|
| 206.8 |
|
December 31, 2016 |
| February 10, 2017 |
|
| 198.1 |
|
|
| 195.3 |
|
Three Months Ended |
| Date Paid or To Be Paid |
| Total Distributions |
|
| Distributions to Targa Resources Corp. |
| ||
September 30, 2020 |
| November 13, 2020 | $ |
| 51.7 |
| $ |
| 48.9 |
|
June 30, 2020 |
| August 13, 2020 |
|
| 51.7 |
|
|
| 48.9 |
|
March 31, 2020 |
| May 13, 2020 |
|
| 53.1 |
|
|
| 50.3 |
|
December 31, 2019 |
| February 13, 2020 |
|
| 241.9 |
|
|
| 239.1 |
|
Contributions
Subsequent to December 1, 2016, the effective date of the Third A&R Partnership Agreement, no units will be issued for
All capital contributions to us but all capital contributions will continue to be allocated 98% to the limited partner and 2% to theour general partner.partner; however, 0 units will be issued for those contributions. For the nine months ended September 30, 2017,2020, TRC made a total capitalof $50.0 million in contributions to us of $1,620.0 million. us.
Preferred Units
In October 2015, we completed an offering of 5,000,000Our Preferred Units at a price of $25.00 per unit. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”
At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equalrank senior to all accumulated and unpaid distributions thereonour common units with respect to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. Holders of Preferred Units have no voting rights except for certain exceptions set forth in our Partnership Agreement.
distribution rights. Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on
our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.
We paid $2.8 million and $8.4 million of distributions to the holders of preferred unitsPreferred Units (“Preferred Unitholders”) duringfor the three and nine months ended September 30, 2017. The Preferred Units are reported as noncontrolling interests in our financial statements.2020.
Subsequent Event
In October 2017,2020, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit. This distributionUnit, resulting in approximately $0.9 million in distributions that will be paid on November 15, 2017.16, 2020.
Note 138 — Derivative Instruments and Hedging Activities
The primary purposepurposes of our commodity risk management activities isare to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedgedentered into derivative instruments to hedge the commodity pricesprice risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, and (ii) future commodity purchases and sales in our Logistics and MarketingTransportation segment by entering into derivative instruments. Theseand (iii) natural gas transportation basis risk in our Logistics and Transportation segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We haveprices and are designated these derivative contracts as cash flow hedges for accounting purposes.
The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.
We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.
As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $1.4 million and $6.3 million for the three and nine months ended September 30, 2017 and $5.8 million and $20.9 million for the three and nine months ended September 30, 2016, related to these novated contracts. From the acquisition date through September 30, 2017, we have received derivative settlements of $100.9 million. The remainder of the novated contracts will settle by the end of 2017. These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.
The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, we recorded ineffectiveness losses of less than $0.1 million and $0.1 million for the three and nine months ended September 30, 2017 and less than $0.1 million and $0.3 million for the three and nine months ended September 30, 2016, related to otherwise qualifying TPL derivatives, which are primarily natural gas swaps.
We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.
At September 30, 2017,2020, the notional volumes of our commodity derivative contracts were:
Commodity | Instrument | Unit | 2017 |
| 2018 |
| 2019 |
| 2020 |
| Instrument | Unit | 2020 |
| 2021 |
| 2022 |
| 2023 |
| 2024 |
| 2025 |
| ||||||||||
Natural Gas | Swaps | MMBtu/d |
| 160,347 |
| 151,100 |
| 116,136 |
| - |
| |||||||||||||||||||||||
Natural Gas | Basis Swaps | MMBtu/d |
| 92,200 |
| 15,726 |
| 12,500 |
| 10,445 |
| |||||||||||||||||||||||
Natural Gas | Futures | MMBtu/d |
| - |
| 1,103 |
| - |
| - |
| Swaps | MMBtu/d |
| 168,317 |
| 166,216 |
| 90,600 |
| 33,350 |
| 0 |
| 0 |
| ||||||||
Natural Gas | Options | MMBtu/d |
| 22,900 |
| 9,486 |
| - |
| - |
| Basis Swaps | MMBtu/d |
| 445,084 |
| 471,168 |
| 295,390 |
| 250,000 |
| 90,000 |
| 5,000 |
| ||||||||
NGL | Swaps | Bbl/d |
| 23,432 |
| 12,858 |
| 7,399 |
| - |
| Swaps | Bbl/d |
| 30,909 |
| 29,261 |
| 16,848 |
| 2,627 |
| 0 |
| 0 |
| ||||||||
NGL | Futures | Bbl/d |
| 38,880 |
| 6,589 |
| 329 |
| - |
| Futures | Bbl/d |
| 52,685 |
| 25,526 |
| 0 |
| 0 |
| 0 |
| 0 |
| ||||||||
NGL | Options | Bbl/d |
| 3,094 |
| 2,986 |
| 410 |
| - |
| |||||||||||||||||||||||
Condensate | Swaps | Bbl/d |
| 3,150 |
| 2,420 |
| 1,293 |
| - |
| Swaps | Bbl/d |
| 5,190 |
| 4,872 |
| 2,125 |
| 515 |
| 0 |
| 0 |
| ||||||||
Condensate | Options | Bbl/d |
| 1,380 |
| 691 |
| 590 |
| - |
|
Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair valuesvalue of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:
|
|
|
| Fair Value as of September 30, 2017 |
|
| Fair Value as of December 31, 2016 |
|
|
|
| Fair Value as of September 30, 2020 |
|
| Fair Value as of December 31, 2019 |
| ||||||||||||||||||||
|
| Balance Sheet |
| Derivative |
|
| Derivative |
|
| Derivative |
|
| Derivative |
|
| Balance Sheet |
| Derivative |
|
| Derivative |
|
| Derivative |
|
| Derivative |
| ||||||||
|
| Location |
| Assets |
|
| Liabilities |
|
| Assets |
|
| Liabilities |
|
| Location |
| Assets |
|
| Liabilities |
|
| Assets |
|
| Liabilities |
| ||||||||
Derivatives designated as hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
| Current |
| $ | 18.4 |
|
| $ | 79.9 |
|
| $ | 16.7 |
|
| $ | 48.6 |
|
| Current |
| $ | 58.4 |
|
| $ | 116.1 |
|
| $ | 102.1 |
|
| $ | 11.6 |
|
|
| Long-term |
|
| 13.7 |
|
|
| 14.4 |
|
|
| 5.1 |
|
|
| 26.1 |
|
| Long-term |
|
| 14.0 |
|
|
| 62.8 |
|
|
| 33.7 |
|
|
| 6.4 |
|
Total derivatives designated as hedging instruments |
|
|
| $ | 32.1 |
|
| $ | 94.3 |
|
| $ | 21.8 |
|
| $ | 74.7 |
|
|
|
| $ | 72.4 |
|
| $ | 178.9 |
|
| $ | 135.8 |
|
| $ | 18.0 |
|
Derivatives not designated as hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
| Current |
| $ | 0.3 |
|
| $ | 1.0 |
|
| $ | 0.1 |
|
| $ | 0.5 |
|
| Current |
| $ | 30.5 |
|
| $ | 5.0 |
|
| $ | 1.2 |
|
| $ | 92.5 |
|
|
| Long-term |
|
| - |
|
|
| 0.5 |
|
|
| - |
|
|
| - |
|
| Long-term |
|
| 65.5 |
|
|
| 0.1 |
|
|
| 1.8 |
|
|
| 34.4 |
|
Total derivatives not designated as hedging instruments |
|
|
| $ | 0.3 |
|
| $ | 1.5 |
|
| $ | 0.1 |
|
| $ | 0.5 |
|
|
|
| $ | 96.0 |
|
| $ | 5.1 |
|
| $ | 3.0 |
|
| $ | 126.9 |
|
Total current position |
|
|
| $ | 18.7 |
|
| $ | 80.9 |
|
| $ | 16.8 |
|
| $ | 49.1 |
|
|
|
| $ | 88.9 |
|
| $ | 121.1 |
|
| $ | 103.3 |
|
| $ | 104.1 |
|
Total long-term position |
|
|
|
| 13.7 |
|
|
| 14.9 |
|
|
| 5.1 |
|
|
| 26.1 |
|
|
|
|
| 79.5 |
|
|
| 62.9 |
|
|
| 35.5 |
|
|
| 40.8 |
|
Total derivatives |
|
|
| $ | 32.4 |
|
| $ | 95.8 |
|
| $ | 21.9 |
|
| $ | 75.2 |
|
|
|
| $ | 168.4 |
|
| $ | 184.0 |
|
| $ | 138.8 |
|
| $ | 144.9 |
|
The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:
| Gross Presentation |
|
| Pro forma net presentation |
|
|
| Gross Presentation |
|
| Pro Forma Net Presentation |
| |||||||||||||||||||||||||||||
September 30, 2017 | Asset |
|
| Liability |
|
| Collateral |
|
| Asset |
|
| Liability |
| |||||||||||||||||||||||||||
September 30, 2020 | September 30, 2020 |
| Asset |
|
| Liability |
|
| Collateral |
|
| Asset |
|
| Liability |
| |||||||||||||||||||||||||
Current Position | Current Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Counterparties with offsetting positions or collateral | $ | 18.7 |
|
| $ | (79.5 | ) |
| $ | 44.6 |
|
| $ | 3.6 |
|
| $ | (19.8 | ) | Counterparties with offsetting positions or collateral |
| $ | 80.3 |
|
| $ | (121.1 | ) |
| $ | 60.1 |
|
| $ | 31.5 |
|
| $ | (12.2 | ) |
| Counterparties without offsetting positions - assets |
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
| Counterparties without offsetting positions - assets |
|
| 8.6 |
|
|
| - |
|
|
| - |
|
|
| 8.6 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| (1.4 | ) |
|
| - |
|
|
| - |
|
|
| (1.4 | ) | Counterparties without offsetting positions - liabilities |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
|
| 18.7 |
|
|
| (80.9 | ) |
|
| 44.6 |
|
|
| 3.6 |
|
|
| (21.2 | ) |
|
|
| 88.9 |
|
|
| (121.1 | ) |
|
| 60.1 |
|
|
| 40.1 |
|
|
| (12.2 | ) |
Long Term Position | Long Term Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Long Term Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Counterparties with offsetting positions or collateral |
| 13.5 |
|
|
| (14.2 | ) |
|
| - |
|
|
| 6.5 |
|
|
| (7.2 | ) | Counterparties with offsetting positions or collateral |
|
| 63.4 |
|
|
| (62.6 | ) |
|
| - |
|
|
| 26.3 |
|
|
| (25.5 | ) |
| Counterparties without offsetting positions - assets |
| 0.2 |
|
|
| - |
|
|
| - |
|
|
| 0.2 |
|
|
| - |
| Counterparties without offsetting positions - assets |
|
| 16.1 |
|
|
| - |
|
|
| - |
|
|
| 16.1 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| (0.7 | ) |
|
| - |
|
|
| - |
|
|
| (0.7 | ) | Counterparties without offsetting positions - liabilities |
|
| - |
|
|
| (0.3 | ) |
|
| - |
|
|
| - |
|
|
| (0.3 | ) |
|
|
| 13.7 |
|
|
| (14.9 | ) |
|
| - |
|
|
| 6.7 |
|
|
| (7.9 | ) |
|
|
| 79.5 |
|
|
| (62.9 | ) |
|
| - |
|
|
| 42.4 |
|
|
| (25.8 | ) |
Total Derivatives | Total Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Counterparties with offsetting positions or collateral |
| 32.2 |
|
|
| (93.7 | ) |
|
| 44.6 |
|
|
| 10.1 |
|
|
| (27.0 | ) | Counterparties with offsetting positions or collateral |
|
| 143.7 |
|
|
| (183.7 | ) |
|
| 60.1 |
|
|
| 57.8 |
|
|
| (37.7 | ) |
| Counterparties without offsetting positions - assets |
| 0.2 |
|
|
| - |
|
|
| - |
|
|
| 0.2 |
|
|
| - |
| Counterparties without offsetting positions - assets |
|
| 24.7 |
|
|
| - |
|
|
| - |
|
|
| 24.7 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| (2.1 | ) |
|
| - |
|
|
| - |
|
|
| (2.1 | ) | Counterparties without offsetting positions - liabilities |
|
| - |
|
|
| (0.3 | ) |
|
| - |
|
|
| - |
|
|
| (0.3 | ) |
|
| $ | 32.4 |
|
| $ | (95.8 | ) |
| $ | 44.6 |
|
| $ | 10.3 |
|
| $ | (29.1 | ) |
|
| $ | 168.4 |
|
| $ | (184.0 | ) |
| $ | 60.1 |
|
| $ | 82.5 |
|
| $ | (38.0 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Gross Presentation |
|
| Pro forma net presentation |
|
|
| Gross Presentation |
|
| Pro Forma Net Presentation |
| ||||||||||||||||||||||||||||
December 31, 2016 | Asset |
|
| Liability |
|
| Collateral |
|
| Asset |
|
| Liability |
| |||||||||||||||||||||||||||
December 31, 2019 | December 31, 2019 |
| Asset |
|
| Liability |
|
| Collateral |
|
| Asset |
|
| Liability |
| |||||||||||||||||||||||||
Current Position | Current Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Counterparties with offsetting positions or collateral | $ | 16.8 |
|
| $ | (46.1 | ) |
| $ | 7.0 |
|
| $ | 5.7 |
|
| $ | (28.0 | ) | Counterparties with offsetting positions or collateral |
| $ | 99.8 |
|
| $ | (85.0 | ) |
| $ | (4.9 | ) |
| $ | 56.0 |
|
| $ | (46.1 | ) |
| Counterparties without offsetting positions - assets |
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
| Counterparties without offsetting positions - assets |
|
| 3.5 |
|
|
| - |
|
|
| - |
|
|
| 3.5 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| (3.0 | ) |
|
| - |
|
|
| - |
|
|
| (3.0 | ) | Counterparties without offsetting positions - liabilities |
|
| - |
|
|
| (19.1 | ) |
|
| - |
|
|
| - |
|
|
| (19.1 | ) |
|
|
| 16.8 |
|
|
| (49.1 | ) |
|
| 7.0 |
|
|
| 5.7 |
|
|
| (31.0 | ) |
|
|
| 103.3 |
|
|
| (104.1 | ) |
|
| (4.9 | ) |
|
| 59.5 |
|
|
| (65.2 | ) |
Long Term Position | Long Term Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Long Term Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Counterparties with offsetting positions or collateral |
| 5.1 |
|
|
| (18.7 | ) |
|
| - |
|
|
| - |
|
|
| (13.6 | ) | Counterparties with offsetting positions or collateral |
|
| 33.3 |
|
|
| (40.5 | ) |
|
| - |
|
|
| 18.1 |
|
|
| (25.3 | ) |
| Counterparties without offsetting positions - assets |
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
| Counterparties without offsetting positions - assets |
|
| 2.2 |
|
|
| - |
|
|
| - |
|
|
| 2.2 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| (7.4 | ) |
|
| - |
|
|
| - |
|
|
| (7.4 | ) | Counterparties without offsetting positions - liabilities |
|
| - |
|
|
| (0.3 | ) |
|
| - |
|
|
| - |
|
|
| (0.3 | ) |
|
|
| 5.1 |
|
|
| (26.1 | ) |
|
| - |
|
|
| - |
|
|
| (21.0 | ) |
|
|
| 35.5 |
|
|
| (40.8 | ) |
|
| - |
|
|
| 20.3 |
|
|
| (25.6 | ) |
Total Derivatives | Total Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Counterparties with offsetting positions or collateral |
| 21.9 |
|
|
| (64.8 | ) |
|
| 7.0 |
|
|
| 5.7 |
|
|
| (41.6 | ) | Counterparties with offsetting positions or collateral |
|
| 133.1 |
|
|
| (125.5 | ) |
|
| (4.9 | ) |
|
| 74.1 |
|
|
| (71.4 | ) |
| Counterparties without offsetting positions - assets |
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
| Counterparties without offsetting positions - assets |
|
| 5.7 |
|
|
| - |
|
|
| - |
|
|
| 5.7 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| (10.4 | ) |
|
| - |
|
|
| - |
|
|
| (10.4 | ) | Counterparties without offsetting positions - liabilities |
|
| - |
|
|
| (19.4 | ) |
|
| - |
|
|
| - |
|
|
| (19.4 | ) |
|
| $ | 21.9 |
|
| $ | (75.2 | ) |
| $ | 7.0 |
|
| $ | 5.7 |
|
| $ | (52.0 | ) |
|
| $ | 138.8 |
|
| $ | (144.9 | ) |
| $ | (4.9 | ) |
| $ | 79.8 |
|
| $ | (90.8 | ) |
Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Some of our hedges are futures contracts executed through a brokerbrokers that clearsclear the hedges through an exchange. We maintain a margin deposit with the brokerbrokers in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within other current assetsDeposits on our Consolidated Balance Sheets and is not offset against the fair valuesvalue of our derivative instruments.
The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of $63.4$15.6 million as of September 30, 2017.2020. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.
The following tables reflect amounts recorded in Other Comprehensive Incomecomprehensive income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated:
|
| Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) |
|
| Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) |
| ||||||||||||||||||||||||||
Derivatives in Cash Flow |
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||
Hedging Relationships |
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||
Commodity contracts |
| $ | (106.8 | ) |
| $ | 12.9 |
|
| $ | (10.5 | ) |
| $ | (40.5 | ) |
| $ | (128.7 | ) |
| $ | 118.2 |
|
| $ | (102.6 | ) |
| $ | 167.8 |
|
|
| Gain (Loss) Reclassified from OCI into Income (Effective Portion) |
|
| Gain (Loss) Reclassified from OCI into Income (Effective Portion) |
| ||||||||||||||||||||||||||
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||
Location of Gain (Loss) |
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||
Revenues |
| $ | (2.1 | ) |
| $ | 8.1 |
|
| $ | (2.2 | ) |
| $ | 50.6 |
|
| $ | 19.2 |
|
| $ | 41.5 |
|
| $ | 139.4 |
|
| $ | 106.1 |
|
Based on valuations as of September 30, 2020, we expect to reclassify commodity hedge-related deferred losses of $(106.0) million included in accumulated other comprehensive income into earnings before income taxes through the end of 2023, with $(57.2) million of losses to be reclassified over the next twelve months.
Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the three and nine months ended September 30, 2020, the unrealized mark-to-market gains are primarily attributable to favorable movements in natural gas forward basis prices, as compared to our hedged positions.
|
| Location of Gain |
| Gain (Loss) Recognized in Income on Derivatives |
|
| Location of Gain |
| Gain (Loss) Recognized in Income on Derivatives |
| ||||||||||||||||||||||||||
Derivatives Not Designated |
| Recognized in Income on |
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| Recognized in Income on |
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||
as Hedging Instruments |
| Derivatives |
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| Derivatives |
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||
Commodity contracts |
| Revenue |
| $ | (1.5 | ) |
| $ | (0.3 | ) |
| $ | (2.9 | ) |
| $ | 1.3 |
|
| Revenue |
| $ | 90.0 |
|
| $ | (103.3 | ) |
| $ | 197.9 |
|
| $ | (113.8 | ) |
Based on valuations as of September 30, 2017, we expect to reclassify commodity hedge-related deferred losses of $64.1 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2019, with $63.0 million of losses to be reclassified over the next twelve months.
See Note 149 – Fair Value Measurements and Note 15 – Segment Information for additional disclosures related to derivative instruments and hedging activities.
Note 149 — Fair Value Measurements
Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.
Fair Value of Derivative Financial Instruments
Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.
The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at September 30, 2017,2020, a net liability position of $63.4$15.6 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $149.9 million, ignoring an adjustment for counterparty credit risk.$(136.8) million. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $22.2 million, ignoring an adjustment for counterparty credit risk.$106.1 million.
Fair Value of Other Financial Instruments
Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:
The TRP Revolver and the accounts receivable securitization facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and
• | The TRP Revolver and the Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and |
Senior unsecured notes are based on quoted market prices derived from trades of the debt.
• | Senior unsecured notes are based on quoted market prices derived from trades of the debt. |
Contingent consideration liabilities related to business acquisitions are carried at fair value.value until the end of the related earn-out period.
We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:
Level 1 – observable inputs such as quoted prices in active markets;
• | Level 1 – observable inputs such as quoted prices in active markets; |
Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and
• | Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and |
Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.
• | Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions. |
The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:
|
|
| September 30, 2017 |
|
| September 30, 2020 |
| ||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
| Fair Value |
|
|
|
|
|
| Fair Value |
| ||||||||||||||||||||||||||
|
|
| Carrying Value |
|
| Total |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Carrying Value |
|
| Total |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
| ||||||||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: | Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from commodity derivative contracts (1) | Assets from commodity derivative contracts (1) |
| $ | 32.0 |
|
| $ | 32.0 |
|
| $ | — |
|
| $ | 29.0 |
|
| $ | 3.0 |
|
| $ | 168.4 |
|
| $ | 168.4 |
|
| $ | — |
|
| $ | 168.4 |
|
| $ | — |
|
Liabilities from commodity derivative contracts (1) | Liabilities from commodity derivative contracts (1) |
|
| 95.4 |
|
|
| 95.4 |
|
|
| — |
|
|
| 86.5 |
|
|
| 8.9 |
|
|
| 184.0 |
|
|
| 184.0 |
|
|
| — |
|
|
| 183.7 |
|
|
| 0.3 |
|
Permian Acquisition contingent consideration (2) |
|
|
| 290.8 |
|
|
| 290.8 |
|
|
| — |
|
|
| — |
|
|
| 290.8 |
| ||||||||||||||||||||
TPL contingent consideration (3) |
|
| 2.5 |
|
|
| 2.5 |
|
|
| — |
|
|
| — |
|
|
| 2.5 |
| |||||||||||||||||||||
TPL contingent consideration (2) |
|
| 2.3 |
|
|
| 2.3 |
|
|
| — |
|
|
| — |
|
|
| 2.3 |
| |||||||||||||||||||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: | Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents | Cash and cash equivalents |
|
| 103.9 |
|
|
| 103.9 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 248.0 |
|
|
| 248.0 |
|
|
| — |
|
|
| — |
|
|
| — |
|
TRP Revolver | TRP Revolver |
|
| 430.0 |
|
|
| 430.0 |
|
|
| — |
|
|
| 430.0 |
|
|
| — |
|
|
| 100.0 |
|
|
| 100.0 |
|
|
| — |
|
|
| 100.0 |
|
|
| — |
|
Senior unsecured notes | Senior unsecured notes |
|
| 3,778.5 |
|
|
| 3,881.2 |
|
|
| — |
|
|
| 3,881.2 |
|
|
| — |
|
|
| 7,145.0 |
|
|
| 7,206.0 |
|
|
| — |
|
|
| 7,206.0 |
|
|
| — |
|
Accounts receivable securitization facility |
|
| 278.1 |
|
|
| 278.1 |
|
|
| — |
|
|
| 278.1 |
|
|
| — |
| |||||||||||||||||||||
Securitization Facility |
|
| 250.0 |
|
|
| 250.0 |
|
|
| — |
|
|
| 250.0 |
|
|
| — |
| |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| December 31, 2016 |
| December 31, 2019 |
| ||||||||||||||||||||||||||||||||||||
|
|
|
|
|
| Fair Value |
|
|
|
|
| Fair Value |
| ||||||||||||||||||||||||||||
|
|
| Carrying Value |
| Total |
| Level 1 |
| Level 2 |
| Level 3 |
|
| Carrying Value |
| Total |
| Level 1 |
| Level 2 |
| Level 3 |
| ||||||||||||||||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: | Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from commodity derivative contracts (1) | Assets from commodity derivative contracts (1) |
| $ | 21.0 |
|
| $ | 21.0 |
|
| $ | — |
|
| $ | 19.6 |
|
| $ | 1.4 |
|
| $ | 136.5 |
|
| $ | 136.5 |
|
| $ | — |
|
| $ | 136.2 |
|
| $ | 0.3 |
|
Liabilities from commodity derivative contracts (1) | Liabilities from commodity derivative contracts (1) |
|
| 74.2 |
|
|
| 74.2 |
|
|
| — |
|
|
| 69.3 |
|
|
| 4.9 |
|
|
| 142.6 |
|
|
| 142.6 |
|
|
| — |
|
|
| 142.0 |
|
|
| 0.6 |
|
Permian Acquisition contingent consideration (2) |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
| ||||||||||||||||||||
TPL contingent consideration (3) |
|
| 2.6 |
|
|
| 2.6 |
|
|
| — |
|
|
| — |
|
|
| 2.6 |
| |||||||||||||||||||||
TPL contingent consideration (2) |
|
| 2.3 |
|
|
| 2.3 |
|
|
| — |
|
|
| — |
|
|
| 2.3 |
| |||||||||||||||||||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: | Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents | Cash and cash equivalents |
|
| 68.0 |
|
|
| 68.0 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 291.1 |
|
|
| 291.1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
TRP Revolver | TRP Revolver |
|
| 150.0 |
|
|
| 150.0 |
|
|
| — |
|
|
| 150.0 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Senior unsecured notes | Senior unsecured notes |
|
| 4,057.3 |
|
|
| 4,101.6 |
|
|
| — |
|
|
| 4,101.6 |
|
|
| — |
|
|
| 7,028.5 |
|
|
| 7,376.9 |
|
|
| — |
|
|
| 7,376.9 |
|
|
| — |
|
Accounts receivable securitization facility |
|
| 275.0 |
|
|
| 275.0 |
|
|
| — |
|
|
| 275.0 |
|
|
| — |
| |||||||||||||||||||||
Securitization Facility |
|
| 370.0 |
|
|
| 370.0 |
|
|
| — |
|
|
| 370.0 |
|
|
| — |
|
(1) | The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note |
(2) |
|
| We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value. |
Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets
We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable market prices or implied volatilities or market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.
The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.
As of September 30, 2017, we had 31 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives arewere (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable iswas immaterial. As of September 30, 2020, we had 3 commodity swap and option contracts categorized as Level 3.
The fair value of the Permian Acquisition contingent consideration was determined using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate. The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are not observable; therefore, the entire valuationsvaluation of the contingent considerations areconsideration is categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) in the Consolidated Statements of Operations.
The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
|
|
| Commodity |
|
|
|
|
| |
|
|
| Derivative Contracts |
|
| Contingent |
| ||
|
|
| Asset/(Liability) |
|
| Liability |
| ||
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2016 |
| $ | (3.6 | ) |
| $ | (2.6 | ) | |
| Change in fair value of TPL contingent consideration |
|
| - |
|
|
| 0.1 |
|
| Fair value of Permian Acquisition contingent consideration (1) |
|
| - |
|
|
| (290.8 | ) |
| New Level 3 derivative instruments |
|
| (0.8 | ) |
|
| - |
|
| Transfers out of Level 3 (2) |
|
| 1.6 |
|
|
| - |
|
| Settlements included in Revenue |
|
| 0.4 |
|
|
| - |
|
| Unrealized gain/(loss) included in OCI |
|
| (3.5 | ) |
|
| - |
|
Balance, September 30, 2017 |
| $ | (5.9 | ) |
| $ | (293.3 | ) |
|
|
| Commodity |
|
|
|
|
| |
|
|
| Derivative Contracts |
|
| Contingent |
| ||
|
|
| Asset/(Liability) |
|
| Consideration |
| ||
Balance, December 31, 2019 |
| $ | (0.3 | ) |
| $ | (2.3 | ) | |
New Level 3 derivative instruments |
|
| (0.5 | ) |
|
| — |
| |
Transfers out of Level 3 (1) |
|
| 0.3 |
|
|
| — |
| |
Unrealized gain/(loss) included in OCI |
|
| 0.2 |
|
|
| — |
| |
Balance, September 30, 2020 |
| $ | (0.3 | ) |
| $ | (2.3 | ) |
(1) |
|
| Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term. |
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Nonfinancial assets and liabilities, such as long-lived assets, are measured at fair value on a nonrecurring basis upon impairment. In the first quarter of 2020, we recorded non-cash pre-tax impairments of $2,442.8 million. The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our Mid-Continent operations and full impairment of our Coastal operations. For disclosures related to valuation techniques, see Note 4 – Property, Plant and Equipment and Intangible Assets.
The techniques described above may produce a fair value calculation that may not be indicative or reflective of future fair values. Furthermore, while we believe our valuation techniques are appropriate and consistent with other market participants, the use of different techniques or assumptions to determine fair value of certain financial and nonfinancial assets and liabilities could result in a different fair value measurement at the reporting date.
Note 1510 — Related Party Transactions -– Targa
Relationship with Targa
We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.
Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities.company. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.
The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.Targa:
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| |||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||
Targa billings of payroll and related costs included in operating expense |
| $ | 54.0 |
|
| $ | 42.6 |
|
| $ | 148.6 |
|
| $ | 125.0 |
| |||||||||||||||
Targa billings of payroll and related costs included in operating expenses | $ | 59.5 |
|
| $ | 61.6 |
|
| $ | 191.7 |
|
| $ | 177.3 |
| ||||||||||||||||
Targa allocation of general and administrative expense |
|
| 43.2 |
|
|
| 40.1 |
|
|
| 126.6 |
|
|
| 117.7 |
|
| 51.3 |
|
|
| 59.5 |
|
|
| 159.8 |
|
|
| 188.4 |
|
Cash distributions to Targa based on IDR, general partner and limited partner ownership (1) |
|
| 222.6 |
|
|
| 178.9 |
|
|
| 624.7 |
|
|
| 395.1 |
| |||||||||||||||
Cash distributions to Targa based on general partner and limited partner ownership |
| 48.8 |
|
|
| 239.6 |
|
|
| 338.3 |
|
|
| 913.1 |
| ||||||||||||||||
Cash contributions from Targa related to limited partner ownership |
|
| 14.7 |
|
|
| 210.7 |
|
|
| 1,587.5 |
|
|
| 1,167.2 |
|
| — |
|
|
| 9.8 |
|
|
| 49.0 |
|
|
| 196.0 |
|
Cash contributions from Targa to maintain its 2% general partner ownership |
|
| 0.3 |
|
|
| 4.3 |
|
|
| 32.5 |
|
|
| 23.8 |
|
| — |
|
|
| 0.2 |
|
|
| 1.0 |
|
|
| 4.0 |
|
_______________________
(1) |
|
| The |
Legal Proceedings
We are a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We are also a party to various proceedings with governmental environmental agencies, including but not limited to the U.S. Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business. See Part II—Item 1. Legal Proceedings for further details.
Note 1712 – Revenue
Fixed consideration allocated to remaining performance obligations
The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 19 years.
| 2020 |
|
| 2021 |
|
| 2022 and after |
| |||
Fixed consideration to be recognized as of September 30, 2020 | $ | 140.7 |
|
| $ | 518.1 |
|
| $ | 2,858.8 |
|
Based on the optional exemptions we elected to apply, the amounts presented in the table above exclude remaining performance obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration of one year or less.
For disclosures related to disaggregated revenue, see Note 15– Segment Information.
Note 13 — Other Operating (Income) Expense
Other operating (income) expense is comprised of the following:
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
Loss on sale or disposal of assets (1) | $ | 0.3 |
|
| $ | 4.7 |
|
| $ | 16.6 |
|
| $ | 5.7 |
|
Miscellaneous business tax |
| 0.3 |
|
|
| 0.2 |
|
|
| 0.6 |
|
|
| 0.4 |
|
| $ | 0.6 |
|
| $ | 4.9 |
|
| $ | 17.2 |
|
| $ | 6.1 |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
(Gain) loss on sale of disposition of business and assets (1) | $ | 58.0 |
|
| $ | 0.5 |
|
| $ | 58.0 |
|
| $ | 3.6 |
|
Write-down of assets (2) |
| 13.5 |
|
|
| 17.9 |
|
|
| 13.5 |
|
|
| 17.9 |
|
Other |
| 0.7 |
|
|
| — |
|
|
| 2.3 |
|
|
| 0.2 |
|
| $ | 72.2 |
|
| $ | 18.4 |
|
| $ | 73.8 |
|
| $ | 21.7 |
|
(1) |
|
(2) | Related to the write-down of certain assets to their recoverable amounts. |
Note 1814 — Supplemental Cash Flow Information
| Nine Months Ended September 30, |
| |||||
| 2020 |
|
| 2019 |
| ||
Cash: |
|
|
|
|
|
|
|
Interest paid, net of capitalized interest (1) | $ | 306.3 |
|
| $ | 216.6 |
|
Income taxes paid, net of refunds |
| 0.1 |
|
|
| (1.7 | ) |
Non-cash investing activities: |
|
|
|
|
|
|
|
Impact of capital expenditure accruals on property, plant and equipment, net |
| (194.7 | ) |
|
| (150.6 | ) |
Transfers from materials and supplies inventory to property, plant and equipment |
| 1.9 |
|
|
| 21.7 |
|
Non-cash financing activities: |
|
|
|
|
|
|
|
Changes in accrued distributions to noncontrolling interests | $ | 3.9 |
|
| $ | 73.8 |
|
|
| Nine Months Ended September 30, |
| ||||||
|
| 2017 |
|
|
| 2016 |
| ||
Cash: |
|
|
|
|
|
|
|
|
|
Interest paid, net of capitalized interest (1) | $ |
| 154.5 |
|
| $ |
| 197.1 |
|
Income taxes paid, net of refunds |
|
| (4.9 | ) |
|
|
| 1.2 |
|
Non-cash investing activities: |
|
|
|
|
|
|
|
|
|
Deadstock commodity inventory transferred to property, plant and equipment | $ |
| 8.3 |
|
| $ |
| 16.9 |
|
Impact of capital expenditure accruals on property, plant and equipment |
|
| 118.3 |
|
|
|
| (0.5 | ) |
Transfers from materials and supplies inventory to property, plant and equipment |
|
| 2.8 |
|
|
|
| 1.9 |
|
Contribution of property, plant and equipment to investments in unconsolidated affiliates |
|
| 1.0 |
|
|
|
| — |
|
Change in ARO liability and property, plant and equipment due to revised cash flow estimate |
|
| 3.1 |
|
|
|
| (9.2 | ) |
Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Acquisitions and Divestitures): |
|
|
|
|
|
|
|
|
|
Contingent consideration recorded at the acquisition date | $ |
| 416.3 |
|
| $ |
| — |
|
Non-cash financing activities: |
|
|
|
|
|
|
|
|
|
Cancellation of treasury units | $ |
| — |
|
| $ |
| (10.4 | ) |
Accrued distributions on unvested equity awards under share compensation arrangements |
|
| — |
|
|
|
| 0.2 |
|
_____________
(1) | Interest capitalized on major projects was |
Note 1915 — SegmentSegment Information
We operate in two2 primary segments: (i) Gathering and Processing, and (ii) Logistics and MarketingTransportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.
Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil purchase and sale, gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico;Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and inThree Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and MarketingTransportation segment includes all the activities and assets necessary to convert mixed NGLs into NGL products and provides certain value addedalso includes other assets and value-added services such as transporting, storing, fractionating, terminaling distributing and marketing of NGLs the storage and terminaling of refined petroleumNGL products, and crude oilincluding services to LPG exporters; and certain natural gas supply and marketing activities in support of our other businesses including services to LPG exporters. Itbusinesses. The Logistics and Transportation segment also includes certain natural gas supply and marketing activities in support of our other operations,the Grand Prix NGL pipeline (“Grand Prix”), as well as transportingour equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas and NGLs. The Logistics and Marketing segment also includes ourpipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix project.
Logisticsconnects our gathering and Marketing operationsprocessing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for pipelines and smaller terminals, are located predominantly located in Mont Belvieu and Galena Park, Texas, and Channelview, Texas;in Lake Charles, Louisiana and Tacoma, Washington.Louisiana.
Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin. and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.
Reportable segment information is shown in the following tables:
|
| Three Months Ended September 30, 2017 |
|
| Three Months Ended September 30, 2020 |
| ||||||||||||||||||||||||||||||||||
|
| Gathering and Processing |
|
| Logistics and Marketing |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
|
| Gathering and Processing |
|
| Logistics and Transportation |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
| ||||||||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
| $ | 200.3 |
|
| $ | 1,672.2 |
|
| $ | (1.0 | ) |
| $ | — |
|
| $ | 1,871.5 |
|
| $ | 135.7 |
|
| $ | 1,616.5 |
|
| $ | 88.6 |
|
| $ | — |
|
| $ | 1,840.8 |
|
Fees from midstream services |
|
| 148.5 |
|
|
| 111.8 |
|
|
| — |
|
|
| — |
|
|
| 260.3 |
|
|
| 126.2 |
|
|
| 148.1 |
|
|
| — |
|
|
| — |
|
|
| 274.3 |
|
|
|
| 348.8 |
|
|
| 1,784.0 |
|
|
| (1.0 | ) |
|
| — |
|
|
| 2,131.8 |
|
|
| 261.9 |
|
|
| 1,764.6 |
|
|
| 88.6 |
|
|
| — |
|
|
| 2,115.1 |
|
Intersegment revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
|
| 783.7 |
|
|
| 80.6 |
|
|
| — |
|
|
| (864.3 | ) |
|
| — |
|
|
| 611.9 |
|
|
| 37.4 |
|
|
| — |
|
|
| (649.3 | ) |
|
| — |
|
Fees from midstream services |
|
| 1.7 |
|
|
| 7.0 |
|
|
| — |
|
|
| (8.7 | ) |
|
| — |
|
|
| 1.7 |
|
|
| 8.5 |
|
|
| — |
|
|
| (10.2 | ) |
|
| — |
|
|
|
| 785.4 |
|
|
| 87.6 |
|
|
| — |
|
|
| (873.0 | ) |
|
| — |
|
|
| 613.6 |
|
|
| 45.9 |
|
|
| — |
|
|
| (659.5 | ) |
|
| — |
|
Revenues |
| $ | 1,134.2 |
|
| $ | 1,871.6 |
|
| $ | (1.0 | ) |
| $ | (873.0 | ) |
| $ | 2,131.8 |
|
| $ | 875.5 |
|
| $ | 1,810.5 |
|
| $ | 88.6 |
|
| $ | (659.5 | ) |
| $ | 2,115.1 |
|
Operating margin |
| $ | 198.3 |
|
| $ | 115.9 |
|
| $ | (1.0 | ) |
| $ | — |
|
| * |
|
| $ | 261.0 |
|
| $ | 280.4 |
|
| $ | 88.6 |
|
| $ | — |
|
| $ | 630.0 |
| |
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1) |
| $ | 10,644.3 |
|
| $ | 3,240.9 |
|
| $ | 30.8 |
|
| $ | 56.2 |
|
| $ | 13,972.2 |
|
| $ | 8,929.4 |
|
| $ | 6,841.2 |
|
| $ | 78.2 |
|
| $ | 145.8 |
|
| $ | 15,994.6 |
|
Goodwill |
| $ | 256.6 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 256.6 |
|
| $ | 45.2 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 45.2 |
|
Capital expenditures |
| $ | 295.9 |
|
| $ | 71.0 |
|
| $ | — |
|
| $ | 11.8 |
|
| $ | 378.7 |
|
| $ | 63.6 |
|
| $ | 69.0 |
|
| $ | — |
|
| $ | 4.0 |
|
| $ | 136.6 |
|
(1) | Assets in the Corporate |
|
|
| Three Months Ended September 30, 2016 |
|
| Three Months Ended September 30, 2019 |
| |||||||||||||||||||||||||||||||||||
|
| Gathering and Processing |
|
| Logistics and Marketing |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
|
| Gathering and Processing |
|
| Logistics and Transportation |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
| ||||||||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
| $ | 172.2 |
|
| $ | 1,215.3 |
|
| $ | 11.2 |
|
| $ | — |
|
| $ | 1,398.7 |
|
| $ | 292.3 |
|
| $ | 1,403.1 |
|
| $ | (101.2 | ) |
| $ | — |
|
| $ | 1,594.2 |
|
Fees from midstream services |
|
| 120.6 |
|
|
| 133.0 |
|
|
| — |
|
|
| — |
|
|
| 253.6 |
|
|
| 173.0 |
|
|
| 135.3 |
|
|
| — |
|
|
| — |
|
|
| 308.3 |
|
|
|
| 292.8 |
|
|
| 1,348.3 |
|
|
| 11.2 |
|
|
| — |
|
|
| 1,652.3 |
|
|
| 465.3 |
|
|
| 1,538.4 |
|
|
| (101.2 | ) |
|
| — |
|
|
| 1,902.5 |
|
Intersegment revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
|
| 574.8 |
|
|
| 76.3 |
|
|
| — |
|
|
| (651.1 | ) |
|
| — |
|
|
| 534.0 |
|
|
| 34.9 |
|
|
| — |
|
|
| (568.9 | ) |
|
| — |
|
Fees from midstream services |
|
| 1.9 |
|
|
| 6.6 |
|
|
| — |
|
|
| (8.5 | ) |
|
| — |
|
|
| 1.9 |
|
|
| 7.4 |
|
|
| — |
|
|
| (9.3 | ) |
|
| — |
|
|
|
| 576.7 |
|
|
| 82.9 |
|
|
| — |
|
|
| (659.6 | ) |
|
| — |
|
|
| 535.9 |
|
|
| 42.3 |
|
|
| — |
|
|
| (578.2 | ) |
|
| — |
|
Revenues |
| $ | 869.5 |
|
| $ | 1,431.2 |
|
| $ | 11.2 |
|
| $ | (659.6 | ) |
| $ | 1,652.3 |
|
| $ | 1,001.2 |
|
| $ | 1,580.7 |
|
| $ | (101.2 | ) |
| $ | (578.2 | ) |
| $ | 1,902.5 |
|
Operating margin |
| $ | 149.4 |
|
| $ | 126.0 |
|
| $ | 11.2 |
|
| $ | — |
|
|
| * |
|
| $ | 246.5 |
|
| $ | 228.9 |
|
| $ | (101.2 | ) |
| $ | — |
|
| $ | 374.2 |
|
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1) |
| $ | 10,047.3 |
|
| $ | 2,737.5 |
|
| $ | 47.2 |
|
| $ | 76.2 |
|
| $ | 12,908.2 |
|
| $ | 12,326.5 |
|
| $ | 6,475.0 |
|
| $ | 2.9 |
|
| $ | 53.9 |
|
| $ | 18,858.3 |
|
Goodwill |
| $ | 393.0 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 393.0 |
|
| $ | 46.6 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 46.6 |
|
Capital expenditures |
| $ | 97.1 |
|
| $ | 36.2 |
|
| $ | — |
|
| $ | 1.3 |
|
| $ | 134.6 |
|
| $ | 230.3 |
|
| $ | 301.2 |
|
| $ | — |
|
| $ | 10.8 |
|
| $ | 542.3 |
|
(1) | Assets in the Corporate |
* Total operating margin is not presented in this table as it represents a non-GAAP measure.
|
| Nine Months Ended September 30, 2020 |
| |||||||||||||||||
|
| Gathering and Processing |
|
| Logistics and Transportation |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
| |||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
| $ | 512.9 |
|
| $ | 4,172.0 |
|
| $ | 215.9 |
|
| $ | — |
|
| $ | 4,900.8 |
|
Fees from midstream services |
|
| 354.5 |
|
|
| 432.2 |
|
|
| — |
|
|
| — |
|
|
| 786.7 |
|
|
|
| 867.4 |
|
|
| 4,604.2 |
|
|
| 215.9 |
|
|
| — |
|
|
| 5,687.5 |
|
Intersegment revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
|
| 1,444.3 |
|
|
| 140.1 |
|
|
| — |
|
|
| (1,584.4 | ) |
|
| — |
|
Fees from midstream services |
|
| 4.9 |
|
|
| 23.8 |
|
|
| — |
|
|
| (28.7 | ) |
|
| — |
|
|
|
| 1,449.2 |
|
|
| 163.9 |
|
|
| — |
|
|
| (1,613.1 | ) |
|
| — |
|
Revenues |
| $ | 2,316.6 |
|
| $ | 4,768.1 |
|
| $ | 215.9 |
|
| $ | (1,613.1 | ) |
| $ | 5,687.5 |
|
Operating margin |
| $ | 753.7 |
|
| $ | 806.0 |
|
| $ | 215.9 |
|
| $ | — |
|
| $ | 1,775.6 |
|
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1) |
| $ | 8,929.4 |
|
| $ | 6,841.2 |
|
| $ | 78.2 |
|
| $ | 145.8 |
|
| $ | 15,994.6 |
|
Goodwill |
| $ | 45.2 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 45.2 |
|
Capital expenditures |
| $ | 218.0 |
|
| $ | 375.5 |
|
| $ | — |
|
| $ | 16.8 |
|
| $ | 610.3 |
|
|
| Nine Months Ended September 30, 2017 |
| |||||||||||||||||
|
| Gathering and Processing |
|
| Logistics and Marketing |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
| |||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
| $ | 544.4 |
|
| $ | 4,804.8 |
|
| $ | 3.9 |
|
| $ | — |
|
| $ | 5,353.1 |
|
Fees from midstream services |
|
| 399.3 |
|
|
| 359.7 |
|
|
| — |
|
|
| — |
|
|
| 759.0 |
|
|
|
| 943.7 |
|
|
| 5,164.5 |
|
|
| 3.9 |
|
|
| — |
|
|
| 6,112.1 |
|
Intersegment revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
|
| 2,209.2 |
|
|
| 237.8 |
|
|
| — |
|
|
| (2,447.0 | ) |
|
| — |
|
Fees from midstream services |
|
| 5.1 |
|
|
| 21.1 |
|
|
| — |
|
|
| (26.2 | ) |
|
| — |
|
|
|
| 2,214.3 |
|
|
| 258.9 |
|
|
| — |
|
|
| (2,473.2 | ) |
|
| — |
|
Revenues |
| $ | 3,158.0 |
|
| $ | 5,423.4 |
|
| $ | 3.9 |
|
| $ | (2,473.2 | ) |
| $ | 6,112.1 |
|
Operating margin |
| $ | 549.3 |
|
| $ | 358.5 |
|
| $ | 3.9 |
|
| $ | — |
|
| * |
| |
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1) |
| $ | 10,644.3 |
|
| $ | 3,240.9 |
|
| $ | 30.8 |
|
| $ | 56.2 |
|
| $ | 13,972.2 |
|
Goodwill |
| $ | 256.6 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 256.6 |
|
Capital expenditures |
| $ | 730.7 |
|
| $ | 241.8 |
|
| $ | — |
|
| $ | 15.2 |
|
| $ | 987.7 |
|
Business acquisition |
| $ | 987.1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 987.1 |
|
(1) | Assets in the Corporate |
* Total operating margin is not presented in this table as it represents a non-GAAP measure.
| Nine Months Ended September 30, 2016 |
|
| Nine Months Ended September 30, 2019 |
| |||||||||||||||||||||||||||||||||||
|
| Gathering and Processing |
|
| Logistics and Marketing |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
|
| Gathering and Processing |
|
| Logistics and Transportation |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
| ||||||||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
| $ | 441.3 |
|
| $ | 3,384.7 |
|
| $ | 56.9 |
|
| $ | — |
|
| $ | 3,882.9 |
|
| $ | 847.4 |
|
| $ | 4,508.5 |
|
| $ | (101.1 | ) |
| $ | — |
|
| $ | 5,254.8 |
|
Fees from midstream services |
|
| 360.9 |
|
|
| 434.6 |
|
|
| — |
|
|
| — |
|
|
| 795.5 |
|
|
| 549.1 |
|
|
| 393.3 |
|
|
| — |
|
|
| — |
|
|
| 942.4 |
|
|
|
| 802.2 |
|
|
| 3,819.3 |
|
|
| 56.9 |
|
|
| — |
|
|
| 4,678.4 |
|
|
| 1,396.5 |
|
|
| 4,901.8 |
|
|
| (101.1 | ) |
|
| — |
|
|
| 6,197.2 |
|
Intersegment revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
|
| 1,455.8 |
|
|
| 176.3 |
|
|
| — |
|
|
| (1,632.1 | ) |
|
| — |
|
|
| 1,896.5 |
|
|
| 117.0 |
|
|
| — |
|
|
| (2,013.5 | ) |
|
| — |
|
Fees from midstream services |
|
| 5.8 |
|
|
| 15.1 |
|
|
| — |
|
|
| (20.9 | ) |
|
| — |
|
|
| 5.3 |
|
|
| 20.1 |
|
|
| — |
|
|
| (25.4 | ) |
|
| — |
|
|
|
| 1,461.6 |
|
|
| 191.4 |
|
|
| — |
|
|
| (1,653.0 | ) |
|
| — |
|
|
| 1,901.8 |
|
|
| 137.1 |
|
|
| — |
|
|
| (2,038.9 | ) |
|
| — |
|
Revenues |
| $ | 2,263.8 |
|
| $ | 4,010.7 |
|
| $ | 56.9 |
|
| $ | (1,653.0 | ) |
| $ | 4,678.4 |
|
| $ | 3,298.3 |
|
| $ | 5,038.9 |
|
| $ | (101.1 | ) |
| $ | (2,038.9 | ) |
| $ | 6,197.2 |
|
Operating margin |
| $ | 404.1 |
|
| $ | 424.6 |
|
| $ | 56.9 |
|
| $ | — |
|
|
| * |
|
| $ | 716.8 |
|
| $ | 565.0 |
|
| $ | (101.1 | ) |
| $ | — |
|
| $ | 1,180.7 |
|
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1) |
| $ | 10,047.3 |
|
| $ | 2,737.5 |
|
| $ | 47.2 |
|
| $ | 76.2 |
|
| $ | 12,908.2 |
|
| $ | 12,326.5 |
|
| $ | 6,475.0 |
|
| $ | 2.9 |
|
| $ | 53.9 |
|
| $ | 18,858.3 |
|
Goodwill |
| $ | 393.0 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 393.0 |
|
| $ | 46.6 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 46.6 |
|
Capital expenditures |
| $ | 271.3 |
|
| $ | 151.9 |
|
| $ | — |
|
| $ | 3.3 |
|
| $ | 426.5 |
|
| $ | 1,068.7 |
|
| $ | 1,197.5 |
|
| $ | — |
|
| $ | 38.7 |
|
| $ | 2,304.9 |
|
(1) | Assets in the Corporate |
* Total operating margin is not presented in this table as it represents a non-GAAP measure.
The following table shows our consolidated revenues disaggregated by product and service for the periods presented:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||
Sales of commodities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue recognized from contracts with customers: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Natural gas |
| $ | 504.1 |
|
| $ | 465.6 |
|
| $ | 1,480.9 |
|
| $ | 1,102.0 |
|
| $ | 351.1 |
|
| $ | 305.3 |
|
| $ | 893.9 |
|
| $ | 934.2 |
|
NGL |
|
| 1,274.9 |
|
|
| 866.7 |
|
|
| 3,623.9 |
|
|
| 2,575.8 |
|
|
| 1,312.9 |
|
|
| 1,160.5 |
|
|
| 3,382.0 |
|
|
| 3,752.4 |
|
Condensate |
|
| 44.9 |
|
|
| 35.0 |
|
|
| 135.9 |
|
|
| 96.2 |
| ||||||||||||||||
Condensate and crude oil |
|
| 54.4 |
|
|
| 178.7 |
|
|
| 217.8 |
|
|
| 488.4 |
| ||||||||||||||||
Petroleum products |
|
| 48.6 |
|
|
| 20.2 |
|
|
| 108.5 |
|
|
| 52.0 |
|
|
| 13.2 |
|
|
| 11.5 |
|
|
| 69.8 |
|
|
| 87.5 |
|
Derivative activities |
|
| (1.0 | ) |
|
| 11.2 |
|
|
| 3.9 |
|
|
| 56.9 |
| ||||||||||||||||
|
|
| 1,731.6 |
|
|
| 1,656.0 |
|
|
| 4,563.5 |
|
|
| 5,262.5 |
| ||||||||||||||||
Non-customer revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Derivative activities - Hedge |
|
| 19.2 |
|
|
| 41.5 |
|
|
| 139.4 |
|
|
| 106.1 |
| ||||||||||||||||
Derivative activities - Non-hedge (1) |
|
| 90.0 |
|
|
| (103.3 | ) |
|
| 197.9 |
|
|
| (113.8 | ) | ||||||||||||||||
|
|
| 109.2 |
|
|
| (61.8 | ) |
|
| 337.3 |
|
|
| (7.7 | ) | ||||||||||||||||
Total sales of commodities |
|
| 1,840.8 |
|
|
| 1,594.2 |
|
|
| 4,900.8 |
|
|
| 5,254.8 |
| ||||||||||||||||
|
|
| 1,871.5 |
|
|
| 1,398.7 |
|
|
| 5,353.1 |
|
|
| 3,882.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees from midstream services: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fractionating and treating |
|
| 29.8 |
|
|
| 33.2 |
|
|
| 92.8 |
|
|
| 94.8 |
| ||||||||||||||||
Storage, terminaling, transportation and export |
|
| 75.0 |
|
|
| 89.7 |
|
|
| 247.8 |
|
|
| 316.3 |
| ||||||||||||||||
Revenue recognized from contracts with customers: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Gathering and processing |
|
| 138.0 |
|
|
| 110.9 |
|
|
| 368.5 |
|
|
| 329.9 |
|
|
| 123.7 |
|
|
| 171.6 |
|
|
| 347.1 |
|
|
| 543.7 |
|
NGL transportation, fractionation and services |
|
| 43.8 |
|
|
| 45.8 |
|
|
| 116.7 |
|
|
| 122.0 |
| ||||||||||||||||
Storage, terminaling and export |
|
| 96.6 |
|
|
| 84.6 |
|
|
| 285.5 |
|
|
| 254.7 |
| ||||||||||||||||
Other |
|
| 17.5 |
|
|
| 19.8 |
|
|
| 49.9 |
|
|
| 54.5 |
|
|
| 10.2 |
|
|
| 6.3 |
|
|
| 37.4 |
|
|
| 22.0 |
|
Total fees from midstream services |
|
| 274.3 |
|
|
| 308.3 |
|
|
| 786.7 |
|
|
| 942.4 |
| ||||||||||||||||
|
|
| 260.3 |
|
|
| 253.6 |
|
|
| 759.0 |
|
|
| 795.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
| $ | 2,131.8 |
|
| $ | 1,652.3 |
|
| $ | 6,112.1 |
|
| $ | 4,678.4 |
|
| $ | 2,115.1 |
|
| $ | 1,902.5 |
|
| $ | 5,687.5 |
|
| $ | 6,197.2 |
|
(1) | Represents derivative activities that are not designated as hedging instruments under ASC 815. |
The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented:
|
| Three Months Ended September 30, |
|
|
| Nine Months Ended September 30, |
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| |||||||||||||||||||||||
|
|
| 2017 |
|
|
| 2016 |
|
|
| 2017 |
|
|
| 2016 |
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing operating margin |
|
| $ | 198.3 |
|
|
| $ | 149.4 |
|
|
| $ | 549.3 |
|
|
| $ | 404.1 |
| $ | 261.0 |
|
| $ | 246.5 |
|
| $ | 753.7 |
|
| $ | 716.8 |
|
Logistics and Marketing operating margin |
|
|
| 115.9 |
|
|
|
| 126.0 |
|
|
|
| 358.5 |
|
|
|
| 424.6 |
| |||||||||||||||
Logistics and Transportation operating margin |
| 280.4 |
|
|
| 228.9 |
|
|
| 806.0 |
|
|
| 565.0 |
| ||||||||||||||||||||
Other operating margin |
|
|
| (1.0 | ) |
|
|
| 11.2 |
|
|
|
| 3.9 |
|
|
|
| 56.9 |
|
| 88.6 |
|
|
| (101.2 | ) |
|
| 215.9 |
|
|
| (101.1 | ) |
Depreciation and amortization expenses |
|
|
| (208.3 | ) |
|
|
| (184.0 | ) |
|
|
| (602.8 | ) |
|
|
| (563.6 | ) | |||||||||||||||
General and administrative expenses |
|
|
| (46.6 | ) |
|
|
| (44.0 | ) |
|
|
| (139.4 | ) |
|
|
| (132.3 | ) | |||||||||||||||
Impairment of property, plant and equipment |
|
|
| (378.0 | ) |
|
|
| — |
|
|
|
| (378.0 | ) |
|
|
| — |
| |||||||||||||||
Impairment of goodwill |
|
|
| — |
|
|
|
| — |
|
|
|
| — |
|
|
|
| (24.0 | ) | |||||||||||||||
Depreciation and amortization expense |
| (203.7 | ) |
|
| (244.3 | ) |
|
| (647.3 | ) |
|
| (718.9 | ) | ||||||||||||||||||||
General and administrative expense |
| (56.3 | ) |
|
| (65.6 | ) |
|
| (171.7 | ) |
|
| (212.3 | ) | ||||||||||||||||||||
Impairment of long-lived assets |
| — |
|
|
| — |
|
|
| (2,442.8 | ) |
|
| — |
| ||||||||||||||||||||
Interest expense, net |
|
|
| (51.9 | ) |
|
|
| (57.9 | ) |
|
|
| (169.5 | ) |
|
|
| (171.2 | ) |
| (94.9 | ) |
|
| (84.2 | ) |
|
| (283.0 | ) |
|
| (229.2 | ) |
Equity earnings (loss) |
| 18.6 |
|
|
| 10.0 |
|
|
| 54.1 |
|
|
| 15.9 |
| ||||||||||||||||||||
Gain (loss) on sale or disposition of business and assets |
| (58.0 | ) |
|
| (0.5 | ) |
|
| (58.0 | ) |
|
| (3.6 | ) | ||||||||||||||||||||
Write-down of assets |
| (13.5 | ) |
|
| (17.9 | ) |
|
| (13.5 | ) |
|
| (17.9 | ) | ||||||||||||||||||||
Gain (loss) from financing activities |
| (13.7 | ) |
|
| — |
|
|
| 47.4 |
|
|
| (1.4 | ) | ||||||||||||||||||||
Gain (loss) from sale of equity-method investment |
| — |
|
|
| 65.8 |
|
|
| — |
|
|
| 65.8 |
| ||||||||||||||||||||
Change in contingent considerations |
| — |
|
|
| — |
|
|
| — |
|
|
| (8.8 | ) | ||||||||||||||||||||
Other, net |
|
|
| 126.6 |
|
|
|
| (5.8 | ) |
|
|
| 78.4 |
|
|
|
| 5.0 |
|
| 0.6 |
|
|
| — |
|
|
| (0.3 | ) |
|
| (0.1 | ) |
Income (loss) before income taxes |
|
| $ | (245.0 | ) |
|
| $ | (5.1 | ) |
|
| $ | (299.6 | ) |
|
| $ | (0.5 | ) | $ | 209.1 |
|
| $ | 37.5 |
|
| $ | (1,739.5 | ) |
| $ | 70.2 |
|
Item 2. Management’s Discussion and Analysis ofof Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 20162019 (“Annual Report”), as well as the unaudited consolidated financial statements and Notesnotes hereto included in this Quarterly Report on Form 10-Q.
Overview
Targa Resources Partners LP (“we,” “our,” the “Partnership” or “TRP”) is a Delaware limited partnership formed in October 2006 by Targa Resources Corp. (“TRC” or “Targa”). Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC’s acquisition on February 17, 2016 of all our outstanding common units that it and its subsidiaries did not already own. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.“NGLS/PA.”
Targa Resources GP LLC, our general partner, is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa.
On February 17, 2016, TRC completed the previously announced transactions contemplated by the Merger Agreement, by and among us, our general partner, TRC and Merger Sub pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP, with TRP continuing as the surviving entity and as a subsidiary of TRC. Following the closing of the TRC/TRP Merger on February 17, 2016, TRC owns all our outstanding common units.
Our Operations
We are engaged primarily in the business of:
gathering, compressing, treating, processing and selling natural gas;
• | gathering, compressing, treating, processing, transporting and purchasing and selling natural gas; |
storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;
• | transporting, storing, fractionating, treating and purchasing and selling NGLs and NGL products, including services to LPG exporters; and |
gathering, storing, terminaling and selling crude oil; and
storing, terminaling and selling refined petroleum products.
• | gathering, storing, terminaling and purchasing and selling crude oil. |
To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and MarketingTransportation (also referred to as the Downstream Business).
Our Gathering and Processing segment includes assets used in the gathering and purchase and sale of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil purchase and sale, gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico;Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and inThree Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and MarketingTransportation segment includes all the activities and assets necessary to convert mixed NGLs into NGL products and provides certain value addedalso includes other assets and value-added services such as transporting, storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oilexporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and MarketingTransportation segment also includes ourthe Grand Prix project.
LogisticsNGL pipeline (“Grand Prix”), as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix connects our gathering and Marketing operationsprocessing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas. The associated assets, including these pipelines, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly located in Mont Belvieu and Galena Park, Texas, and Channelview, Texas;in Lake Charles, Louisiana and Tacoma, Washington.Louisiana.
Other contains the results (including any hedge ineffectiveness) of our commodityunrealized mark-to-market gains/losses related to derivative activitiescontracts that are included in operating margin.were not designated as cash flow hedges.
Response to Current Market Conditions
During the nine months ended September 30, 2020, global commodity prices declined due to factors that significantly impacted both supply and demand. As the COVID-19 pandemic spread and travel and other restrictions were implemented globally, the demand for commodities declined substantially. Additionally, certain major oil producing nations significantly increased their oil and gas production late in the first quarter which further contributed to the surplus production of commodities. Despite these nations subsequently agreeing to reduce global commodity supplies and global economies beginning to re-open, commodity prices remain weak relative to historical levels and continue to remain volatile. Reduced economic activity due to the COVID-19 pandemic, combined with uncertainty around global commodity supply and demand, has contributed to depressed crude oil, condensate, NGL and natural gas prices. Furthermore, the decline in commodity prices led many exploration and production companies to reduce planned capital expenditures for drilling and production activities and also led to some companies shutting in wells in the first half of 2020. Such price and activity declines negatively impacted our operations by (i) reducing investments by third parties in the development of new oil and gas reserves, therefore reducing volumes coming onto our systems in the future, (ii) decreasing volumes processed in our facilities and transported on our pipelines and (iii) reducing the prices we receive from the sale of commodities. While commodity prices remain low relative to historical levels and uncertainties associated with the impacts of COVID-19 continue, production from wells that were previously shut-in during the first half of 2020 across our operating areas has largely resumed. Though energy demand has begun to recover compared to the first half of 2020, the pace and scope of recovery is uncertain at this time and may extend beyond 2020.
These circumstances have caused significant market volatility and business disruption. In our Gathering and Processing areas of operation, producers have reduced their drilling activity to varying degrees, which may lead to lower volume growth in the near term and reduced demand for our services. Producer activity also generates demand in our Downstream Business for transportation, fractionation, storage and other fee-based services, which may decrease in the near term.
There has been, and we believe will continue to be, significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. Due to the recent volatility in commodity prices, we are uncertain of what pricing and market demand will be throughout 2020, and, as a result, demand for our services may decrease. Across our operations, particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. The significant level of margin we derive from fee-based arrangements, combined with our hedging arrangements, helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Due to the significant decline in commodity prices and the increased volatility in the broader market, the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted. In these conditions, investors may be more likely to limit the amounts of their investments as well as seek more restrictive terms and higher costs on any financing. While these effects have increased the costs of debt and equity financing for the Company and others in our industry, we believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures through the remainder of 2020 and beyond.
In a response to current market conditions, in the first quarter of 2020, we announced that our Board of Directors approved a reduction in the Company’s quarterly common dividend to $0.10 per share for the quarter ended March 31, 2020 from $0.91 per share in the previous quarter. This reduction provided for approximately $755 million of additional annual direct cash flow, resulting in significant free cash flow available to reduce debt. We also reduced our estimated 2020 net growth capital expenditures to about $700 million from our previously disclosed ranges of $700 million to $800 million in the first quarter of 2020 and $1.2 billion to $1.3 billion in the fourth quarter of 2019. The vast majority of spending is for major ongoing growth capital projects where the capital is already predominantly spent. We continue to work through numerous internal initiatives to respond to current market conditions, including identifying and implementing cost reduction measures such as reducing or deferring non-essential operating and general and administrative expenses.
We believe that our long-term strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows even in a low commodity price environment. Geographic, business and customer diversity enhances our ability to generate sufficient cash flows to fund our requirements. Our assets are positioned in strategic oil and gas producing areas across multiple basins and provide services under attractive contract terms to a diverse mix of customers across our operational areas. Our contract portfolio has attractive rates and term characteristics, including a significant fee-based component, especially in our Downstream Business. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices.
We are currently experiencing no material issues with potential workforce disruptions, and we remain focused on safeguarding employee health and safety and ensuring safe and reliable operations in response to COVID-19. Additionally, we are currently experiencing no material supply chain disruptions as a result of the COVID-19 pandemic, and our relationships with our major customers continues to be strong. However, if any of these circumstances change, our business could be adversely affected. Further, as there is significant uncertainty around the breadth and duration of the disruptions to global markets related to the aforementioned current events, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows.
Gathering and Processing Segment Expansion
Permian Acquisition
On March 1, 2017, we completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”).
We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the "initial purchase price"). Contributions from TRC were used to fund the cash portion of the Permian Acquisition purchase price. Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that would occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.
New Delaware's gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity and we are in the process of installing a 60 MMcf/d plant, known as the Oahu Plant, in the Delaware Basin with expectations of commencing operations in the fourth quarter of 2017. Currently, there is 40 MBbl/d of crude gathering capacity on the New Delaware system.
New Midland's gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Midland system.
New Delaware's gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and the New Midland's gas gathering and processing assets were connected to our existing WestTX system in October 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.
Additional Permian System Processing CapacityExpansion
In November 2016,2020, we announced plans to restart the idled 45 MMcf/d Benedumtransfer of an existing cryogenic natural gas processing plant andfrom our North Texas system to add 20 MMcf/d of capacity at our Midkiff Plant in our WestTXPermian Midland system. The Benedumformer Longhorn Plant was idled in September 2014 after the start-up of the 200 MMcf/d Edward Plant,will be relocated to, and was brought back online in the first quarter of 2017. The addition of 20 MMcf/d of capacity at our Midkiff Plant was completed in the second quarter of 2017 and increased overall plant capacity of the Midkiff/Consolidator Plant complexinstalled in Reagan County, Texas, from 210 MMcf/d to 230 MMcf/d. Also in November 2016, we announced plans to build the 200 MMcf/d Joyce Plant, which is expected to be completed in the first quarter of 2018. We expect total net growth capital expenditures for the Joyce Plant to be approximately $80 million.
In May 2017, we announced plans to build a new plant and expand the gathering footprint of our Permian Midland system in the Midland Basin. This project includes2021 as a new 200 MMcf/d cryogenic natural gas processing plant known as(the “Heim Plant”). The Heim Plant will process natural gas production from the Johnson Plant, whichPermian Basin and is expected to begin operations in the thirdfourth quarter of 2018. We expect total net growth capital expenditures for the Johnson Plant to be approximately $100 million.2021.
Also in May 2017,In August 2019, we announced plans to build a new plant and expand the gathering footprintthat we began construction of our Permian Delaware system in the Delaware Basin. This project includes a new 250 MMcf/d cryogenic natural gas processing plant known asin the WildcatMidland Basin, the Gateway Plant, which is expectedcommenced operations in the third quarter of 2020.
Permian Delaware Processing Expansions
In March 2018, we announced that we entered into long-term fee-based agreements with an investment grade energy company for natural gas gathering and processing services in the Delaware Basin and for downstream transportation, fractionation and other related services. The agreements are underpinned by the customer's dedication of significant acreage within a large, well-defined area in the Delaware Basin. In addition to begin high-pressure rich gas gathering pipelines and a natural gas processing plant, the Falcon Plant, which were placed into service in 2019, we commenced operations of a second 250 MMcf/d cryogenic natural gas processing plant, the Peregrine Plant, in the second quarter of 2018. We expect total net growth capital expenditures for the Wildcat Plant to be approximately $130 million.2020.
Eagle Ford Shale Natural Gas GatheringWe provide NGL transportation services on Grand Prix and Processing Joint Ventures
In October 2015, we announced that we had entered into the Carnero Joint Ventures with Sanchez Energy Corporation (“Sanchez”) to construct the 200 MMcf/d Raptor Plant and approximately 45 miles of associated pipelines. In July 2016, Sanchez sold its interest in the gathering joint venture to Sanchez Midstream Partners, L.P. (“SNMP”), formerly known as
Sanchez Production Partners, L.P., and in November 2016, sold its interest in the processing joint venture to SNMP. Through the Carnero Joint Ventures, we indirectly ownfractionation services at our Mont Belvieu complex for a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect SNMP's Catarina gathering system to the plant. We hold the capacity on the high pressure gathering pipelines, and pay the gathering joint venture fees for transportation.
The Raptor Plant began operations in the second quarter of 2017, and is capable of processing 200 MMcf/d. In February 2017, we announced the addition of compression to increase the processing capacitymajority of the Raptor Plant to 260 MMcf/d, which we expect to be completed inNGLs from the fourth quarter of 2017. The Raptor Plant accommodates growing production from Sanchez’s premier Eagle Ford Shale acreage position in Dimmit, La SalleFalcon and Webb Counties, TexasPeregrine Plants.
Logistics and from other third party producers. The plant and high pressure gathering pipelines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We manage operations of the high pressure gathering lines and the plant. Prior to the plant being placed in service, we benefited from Sanchez natural gas volumes that were processed at our Silver Oak facilities in Bee County, Texas.
Eagle Ford Shale Acquisition of Flag City Natural Gas Processing Plant
In May 2017, we acquired a 150 MMcf/d natural gas processing plant (the “Flag City Plant”) and associated assets from subsidiaries of Boardwalk Pipeline Partners, L.P. (“Boardwalk”) for $60.0 million, subject to customary closing adjustments. The gas processing activities under the Flag City Plant contracts have been transferred to our Silver Oak facilities. We shut down the Flag City Plant and are moving the plant and its component parts to other Targa locations.
Badlands
During 2017, we expect to invest approximately $150 million to expand our crude gathering and natural gas processing business in the Williston Basin, North Dakota. The expansion includes the addition of pipelines, LACT units, compression and other infrastructure to support continued growth in producer activity.
Sale of Venice Gathering System, L.L.C.
Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations were assumed by the buyer. VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gas Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. Targa Midstream Services LLC operated the Venice gathering system for four months after closing pursuant to a Transition Services Agreement with VGS.
DownstreamTransportation Segment Expansion
Grand Prix NGL Pipeline Extension
In May 2017,February 2019, we announced an extension to our Grand Prix NGL pipeline system (the “Central Oklahoma Extension”), which will extend from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with The Williams Companies, Inc. (“Williams”) Bluestem Pipeline, linking the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. The Central Oklahoma Extension is expected to be operational by the end of the fourth quarter of 2020. Transportation volumes on the Central Oklahoma Extension accrue solely to Targa’s benefit and are not included in Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest.
Fractionation Expansion
In November 2018, we announced plans to construct atwo new common carrier NGL pipeline. The NGL pipeline110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Grand Prix”Train 7” and “Train 8”). Train 7 commenced operations in the first quarter of 2020 and Train 8 commenced operations in the third quarter of 2020. In January 2019, Williams committed to Targa significant volumes which Targa will transport volumes from the Permian Basinon Grand Prix and our North Texas systemfractionate at Targa’s Mont Belvieu facilities (including Train 7). Williams was also granted an option to our fractionation and storage complexpurchase a 20% equity interest in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supportedfractionation train, which was originally wholly owned by our volumesTarga. Williams exercised its initial option and other third party customer commitments, and is expectedexecuted a joint venture agreement with us with respect to be in serviceTrain 7 in the second quarter of 2019. The capacity of the pipeline from the Permian BasinCertain fractionation-related infrastructure for Train 7, such as storage caverns and brine handling, will be approximately 300 MBbl/d, expandable to 550 MBbl/d.funded and owned 100% by Targa.
LPG Export Expansion
In September 2017,February 2019, we soldannounced plans to funds managedfurther expand our LPG export capabilities of propane and butanes at our Galena Park Marine Terminal by Blackstone Energy Partners ("Blackstone") a 25 percent interest inincreasing refrigeration capacity and associated load rates. With the additional infrastructure, we increased our consolidated subsidiary, Grand Prix Pipeline LLC (the "Grand Prix Joint Venture"). We are the operator and construction manager of Grand Prix. Our share of total growth capital expenditures for Grand Prix is expectedeffective export capacity up to be approximately $975 million, with approximately $275 million of spending in 2017.
Concurrent with the sale of the minority interest15 MMBbl per month in the Grand Prix Joint Venture to Blackstone, wethird quarter of 2020, depending upon the mix of propane and EagleClaw Midstream Ventures, LLC ("EagleClaw"), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement for transportationbutane demand, vessel size and fractionation services whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw's natural gas volumes produced or processed in the Delaware Basin.availability of supply, among other factors.
Gulf Coast Express Pipeline
Asset Sales
In October 2017, we announced that2020, we executed a letter of intent along with Kinder Morganagreements to sell our assets in Channelview, Texas Pipeline LLC, a subsidiary of Kinder Morgan, Inc. (“Kinder Morgan”) and DCP Midstream, LP with respect to the joint development of the proposed Gulf Coast Express Pipeline Project ("GCX Project"), which would provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. Under the terms of the letter of intent, we would own a 25 percent interestapproximately $58 million (the “October 2020 Sale”). The sale closed in the GCX Project. KMTP would serve asfourth quarter of 2020.
In November 2019, we executed agreements to sell our crude and storage business in Permian Delaware for approximately $134 million. The sale closed in the operator and constructorfirst quarter of the GCX Project, and we would commit significant volumes to it, including certain volumes provided by Pioneer Natural Resources Company (“Pioneer”), a joint owner in our WestTX Permian Basin system. The participation of the three parties involved with the GCX Project is subject to negotiation and execution of definitive agreements.2020.
The GCX Project is expected to have capacity of approximately 1.92 billion cubic feet per day, and would include a lateral into the Midland Basin, consisting of approximately 50 miles of 36-inch pipeline and associated compression to serve gas processing facilities owned by us, as well as those owned jointly by us and Pioneer in our WestTX system. The expected in-service date of the pipeline continues to be scheduled for the second half of 2019, pending the timely completion of definitive agreements with shippers and a final investment decision by the three parties.
Financing Activities
On February 23, 2017, we amended our account receivable securitization facility (“Securitization Facility”) to increase the facility size to $350.0 million from $275.0 million.
On June 26, 2017,November 2, 2020, we redeemed the $559.6 million remaining balance of our 6⅜5¼% Senior Notes due August 2022 (“6⅜2023.
In the third quarter of 2020, we issued $1.0 billion of 4⅞% Senior Notes”). The redemption price was 103.188%Notes due 2031, resulting in net proceeds of $991.0 million. A portion of the principal amount. The $278.7net proceeds from the issuance were used to fund the concurrent cash tender offer (the “Tender Offer”) and redemption payments for our 6¾% Senior Notes due 2024 (the “6¾% Notes”), with the remainder used for repayment of borrowings under the TRP Revolver.
We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million principal amount outstanding wasand redeemed on June 26, 2017 for a total redemption payment of $287.6 million, excluding accrued interest.
On October 17, 2017, we issued $750.0 millionthe remaining aggregate principal amount of 5%the 6¾% Notes, which totaled $318.0 million. We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs.
Additionally, during the first half of 2020, we repurchased a portion of our outstanding senior notes due January 2028 (the “5% Senior Notes due 2028”). We usedon the net proceeds of $744.4open market, paying $239.8 million after costs from this offering to redeem our 5% Senior Notes due 2018, reduce borrowings under our credit facilities, and for general partnership purposes.
On October 30, 2017, we redeemed our outstanding 5% Senior Notes due 2018 at par value plus accrued interest throughto repurchase $303.3 million of the redemption date.notes. The redemptionrepurchases resulted in a non-cash loss from financing activities to$61.1 million net gain, which included the write-off $0.2of $2.4 million of unamortizedin related debt issuance costscosts.
We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
In the fourthsecond quarter of 2017.
2020, we amended our accounts receivable securitization facility (the “Securitization Facility”) to decrease the facility size from $400.0 million to $250.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2021.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.
How We Evaluate Our Operations
The profitability of our business segments is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.
Our profitability is also impacted by fee-based revenues. contracts. Our growth strategy, based ongrowing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our downstream facilities, continued focus on adding fee-based margin to our existing facilitiesand future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, has increasedwill continue to increase the percentagenumber of our revenuescontracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability.
Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: gross margin, operating margin, and adjustedAdjusted EBITDA.
Throughput Volumes, Facility Efficiencies and Fuel Consumption
Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third-parties.third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.
In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets.assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.
Operating Expenses
Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, generally remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period.
Capital Expenditures
Our capital expenditures are classified as growth capital expenditures, business acquisitions, and maintenance capital expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.
Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.
Non-GAAP Measures
We utilize non-GAAP measures to analyze our performance. Gross margin, operating margin and Adjusted EBITDA are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP measures is net income (loss) attributable to TRP. These non-GAAP measures should not be considered as an alternative to GAAP net income attributable to TRP and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect net income, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.
Gross Margin
We define gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.
Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas, condensate, crude oil and NGLs and fee revenues related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases.of:
• | service fees related to natural gas and crude oil gathering, treating and processing; and |
• | revenues from the sale of natural gas, condensate, crude oil and NGLs less producer payments, natural gas and crude oil purchases, and our equity volume hedge settlements. |
Logistics and MarketingTransportation segment gross margin consists primarily ofof:
service fee revenues (including the pass-through of energy costs included in fee rates),
�� | service fees (including the pass-through of energy costs included in fee rates); |
system product gains and losses, and
• | system product gains and losses; and |
• | NGL and natural gas sales, less NGL and natural gas purchases, third-party transportation costs and the net inventory change. |
NGL and natural gas sales, less NGL and natural gas purchases, transportation costs and the net inventory change.
The gross margin impacts of cash flowmark-to-market hedge settlementsunrealized changes in fair value are reported in Other.
Operating Margin
We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations.
Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of our financial statements, including investors and commercial banks, to assess:
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.
| • | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
• | our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and |
• | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
Adjusted EBITDA
We define Adjusted EBITDA as net income (loss) attributable to TRP before: interest;before interest, income taxes; depreciation and amortization; impairments of goodwill and property, plant and equipment; gains or losses on debt repurchases, redemptions, amendments, exchanges and early debt extinguishments and asset disposals; risk management activities related to derivative instruments, including the cash impact of hedges acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015; non-cash compensation on equity grants; transaction costs related to business acquisitions; the Splitter Agreement adjustment; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion oftaxes, depreciation and amortization, expense.and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the Adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others. The economic substance behind our use of Adjusted EBITDA isothers to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to holders of our investors.equity interests.
Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable to TRP. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.
Our Non-GAAP Financial Measures
The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated.indicated:
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||||
| 2017 |
|
| 2016 |
|
|
| 2017 |
|
| 2016 |
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| |||||||||
| (In millions) |
|
| (In millions) |
| ||||||||||||||||||||||||||||
Reconciliation of Net Income (loss) to TRP Operating Margin and Gross Margin: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Reconciliation of Net Income (Loss) to Operating Margin and Gross Margin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net income (loss) |
| $ | (245.0 | ) |
| $ | (6.1 | ) |
|
| $ | (295.4 | ) |
| $ | (0.5 | ) |
| $ | 209.1 |
|
| $ | 37.5 |
|
| $ | (1,739.5 | ) |
| $ | 70.2 |
|
Depreciation and amortization expense |
|
| 208.3 |
|
|
| 184.0 |
|
|
|
| 602.8 |
|
|
| 563.6 |
|
|
| 203.7 |
|
|
| 244.3 |
|
|
| 647.3 |
|
|
| 718.9 |
|
General and administrative expense |
|
| 46.6 |
|
|
| 44.0 |
|
|
|
| 139.4 |
|
|
| 132.3 |
|
|
| 56.3 |
|
|
| 65.6 |
|
|
| 171.7 |
|
|
| 212.3 |
|
Impairment of property, plant and equipment |
|
| 378.0 |
|
|
| — |
|
|
|
| 378.0 |
|
|
| �� |
| ||||||||||||||||
Impairment of goodwill |
|
| — |
|
|
| — |
|
|
|
| — |
|
|
| 24.0 |
| ||||||||||||||||
Interest expense, net |
|
| 51.9 |
|
|
| 57.9 |
|
|
|
| 169.5 |
|
|
| 171.2 |
| ||||||||||||||||
Income tax expense (benefit) |
|
| — |
|
|
| 1.0 |
|
|
|
| (4.2 | ) |
|
| — |
| ||||||||||||||||
(Gain) loss on sale or disposition of assets |
|
| 0.3 |
|
|
| 4.7 |
|
|
|
| 16.6 |
|
|
| 5.7 |
| ||||||||||||||||
Impairment of long-lived assets |
|
| — |
|
|
| — |
|
|
| 2,442.8 |
|
|
| — |
| |||||||||||||||||
Interest (income) expense, net |
|
| 94.9 |
|
|
| 84.2 |
|
|
| 283.0 |
|
|
| 229.2 |
| |||||||||||||||||
Equity (earnings) loss |
|
| (18.6 | ) |
|
| (10.0 | ) |
|
| (54.1 | ) |
|
| (15.9 | ) | |||||||||||||||||
(Gain) loss on sale or disposition of business and assets |
|
| 58.0 |
|
|
| 0.5 |
|
|
| 58.0 |
|
|
| 3.6 |
| |||||||||||||||||
Write-down of assets |
|
| 13.5 |
|
|
| 17.9 |
|
|
| 13.5 |
|
|
| 17.9 |
| |||||||||||||||||
(Gain) loss from sale of equity-method investment |
|
| — |
|
|
| (65.8 | ) |
|
| — |
|
|
| (65.8 | ) | |||||||||||||||||
(Gain) loss from financing activities |
|
| — |
|
|
| — |
|
|
|
| 10.7 |
|
|
| (21.4 | ) |
|
| 13.7 |
|
|
| — |
|
|
| (47.4 | ) |
|
| 1.4 |
|
Change in contingent considerations |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 8.8 |
| |||||||||||||||||
Other, net |
|
| (126.9 | ) |
|
| 1.1 |
|
|
|
| (105.7 | ) |
|
| 10.7 |
|
|
| (0.6 | ) |
|
| — |
|
|
| 0.3 |
|
|
| 0.2 |
|
Operating margin |
|
| 313.2 |
|
|
| 286.6 |
|
|
|
| 911.7 |
|
|
| 885.6 |
|
|
| 630.0 |
|
|
| 374.2 |
|
|
| 1,775.6 |
|
|
| 1,180.8 |
|
Operating expenses |
|
| 155.5 |
|
|
| 143.0 |
|
|
|
| 462.6 |
|
|
| 413.9 |
|
|
| 181.9 |
|
|
| 200.2 |
|
|
| 565.1 |
|
|
| 600.7 |
|
Gross margin |
| $ | 468.7 |
|
| $ | 429.6 |
|
|
| $ | 1,374.3 |
|
| $ | 1,299.5 |
|
| $ | 811.9 |
|
| $ | 574.4 |
|
| $ | 2,340.7 |
|
| $ | 1,781.5 |
|
| Three Months Ended September 30, |
| Nine Months Ended September 30, |
| ||||||||||||||
| 2017 |
|
| 2016 |
| 2017 |
|
| 2016 |
| ||||||||
| (In millions) |
| ||||||||||||||||
Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to TRP | $ |
| (254.7 | ) |
| $ |
| (10.8 | ) | $ |
| (321.3 | ) |
| $ |
| (14.0 | ) |
Interest expense, net |
|
| 51.9 |
|
|
|
| 57.9 |
|
|
| 169.5 |
|
|
|
| 171.2 |
|
Income tax expense (benefit) |
|
| — |
|
|
|
| 1.0 |
|
|
| (4.2 | ) |
|
|
| — |
|
Depreciation and amortization expense |
|
| 208.3 |
|
|
|
| 184.0 |
|
|
| 602.8 |
|
|
|
| 563.6 |
|
Impairment of property, plant and equipment |
|
| 378.0 |
|
|
|
| — |
|
|
| 378.0 |
|
|
|
| — |
|
Impairment of goodwill |
|
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| 24.0 |
|
(Gain) loss on sale or disposition of assets |
|
| 0.3 |
|
|
|
| 4.7 |
|
|
| 16.6 |
|
|
|
| 5.7 |
|
(Gain) loss from financing activities |
|
| — |
|
|
|
| — |
|
|
| 10.7 |
|
|
|
| (21.4 | ) |
(Earnings) loss from unconsolidated affiliates |
|
| (0.2 | ) |
|
|
| 2.2 |
|
|
| 16.6 |
|
|
|
| 11.4 |
|
Distributions from unconsolidated affiliates and preferred partner interests, net |
|
| 4.6 |
|
|
|
| 3.8 |
|
|
| 15.0 |
|
|
|
| 12.6 |
|
Change in contingent consideration included in Other expense |
|
| (126.8 | ) |
|
|
| (0.3 | ) |
|
| (125.6 | ) |
|
|
| (0.3 | ) |
Compensation on TRP equity grants |
|
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| 2.2 |
|
Transaction costs related to business acquisitions |
|
| 0.4 |
|
|
|
| — |
|
|
| 5.6 |
|
|
|
| — |
|
Splitter Agreement (1) |
|
| 10.8 |
|
|
|
| — |
|
|
| 32.3 |
|
|
|
| — |
|
Risk management activities |
|
| 2.0 |
|
|
|
| 6.2 |
|
|
| 7.2 |
|
|
|
| 18.7 |
|
Noncontrolling interests adjustments (2) |
|
| (5.0 | ) |
|
|
| (8.4 | ) |
|
| (13.6 | ) |
|
|
| (20.5 | ) |
TRP Adjusted EBITDA | $ |
| 269.6 |
|
| $ |
| 240.3 |
| $ |
| 789.6 |
|
| $ |
| 753.2 |
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
|
| (In millions) |
| |||||||||||||
Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to TRP |
| $ | 109.0 |
|
| $ | (39.1 | ) |
| $ | (1,847.6 | ) |
| $ | (74.1 | ) |
Interest (income) expense, net |
|
| 94.9 |
|
|
| 84.2 |
|
|
| 283.0 |
|
|
| 229.2 |
|
Depreciation and amortization expense |
|
| 203.7 |
|
|
| 244.3 |
|
|
| 647.3 |
|
|
| 718.9 |
|
Impairment of long-lived assets |
|
| — |
|
|
| — |
|
|
| 2,442.8 |
|
|
| — |
|
(Gain) loss on sale or disposition of business and assets |
|
| 58.0 |
|
|
| 0.5 |
|
|
| 58.0 |
|
|
| 3.6 |
|
Write-down of assets |
|
| 13.5 |
|
|
| 17.9 |
|
|
| 13.5 |
|
|
| 17.9 |
|
(Gain) loss from sale of equity-method investment |
|
| — |
|
|
| (65.8 | ) |
|
| — |
|
|
| (65.8 | ) |
(Gain) loss from financing activities (1) |
|
| 13.7 |
|
|
| — |
|
|
| (47.4 | ) |
|
| 1.4 |
|
Equity (earnings) loss |
|
| (18.6 | ) |
|
| (10.0 | ) |
|
| (54.1 | ) |
|
| (15.9 | ) |
Distributions from unconsolidated affiliates and preferred partner interests, net |
|
| 28.2 |
|
|
| 14.0 |
|
|
| 81.6 |
|
|
| 33.4 |
|
Change in contingent considerations |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 8.8 |
|
Risk management activities |
|
| (88.3 | ) |
|
| 100.7 |
|
|
| (214.2 | ) |
|
| 100.8 |
|
Severance and related benefits (2) |
|
| — |
|
|
| — |
|
|
| 6.5 |
|
|
| — |
|
Noncontrolling interests adjustments (3) |
|
| (9.2 | ) |
|
| (8.9 | ) |
|
| (211.7 | ) |
|
| (25.6 | ) |
TRP Adjusted EBITDA |
| $ | 404.9 |
|
| $ | 337.8 |
|
| $ | 1,157.7 |
|
| $ | 932.6 |
|
(1) |
|
(2) | Represents one-time severance and related benefit expense related to our cost reduction measures. |
(3) | Noncontrolling interest portion of depreciation and amortization |
Consolidated Results of Operations
The following table and discussion is a summary of our consolidated results of operations:
|
| Three Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
| Three Months Ended September 30, |
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
|
| 2017 |
|
|
| 2016 |
|
|
| 2017 vs. 2016 |
|
|
| 2017 |
|
|
| 2016 |
|
| 2017 vs. 2016 |
| 2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
|
| 2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
| |||||||||||||||||||||||||||||
| (In millions, except operating statistics and price amounts) |
| (In millions) |
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Sales of commodities |
| $ | 1,871.5 |
|
|
| $ | 1,398.7 |
|
|
| $ | 472.8 |
|
|
| 34 | % |
|
| $ | 5,353.1 |
|
|
| $ | 3,882.9 |
|
| $ | 1,470.2 |
|
|
| 38 | % | $ | 1,840.8 |
|
| $ | 1,594.2 |
|
| $ | 246.6 |
|
|
| 15 | % |
| $ | 4,900.8 |
|
| $ | 5,254.8 |
|
| $ | (354.0 | ) |
|
| (7 | %) | |
Fees from midstream services |
|
| 260.3 |
|
|
|
| 253.6 |
|
|
|
| 6.7 |
|
|
| 3 | % |
|
|
| 759.0 |
|
|
|
| 795.5 |
|
|
| (36.5 | ) |
|
| (5 | %) |
| 274.3 |
|
|
| 308.3 |
|
|
| (34.0 | ) |
|
| (11 | %) |
|
| 786.7 |
|
|
| 942.4 |
|
|
| (155.7 | ) |
|
| (17 | %) | |
Total revenues |
|
| 2,131.8 |
|
|
|
| 1,652.3 |
|
|
|
| 479.5 |
|
|
| 29 | % |
|
|
| 6,112.1 |
|
|
|
| 4,678.4 |
|
|
| 1,433.7 |
|
|
| 31 | % |
| 2,115.1 |
|
|
| 1,902.5 |
|
|
| 212.6 |
|
|
| 11 | % |
|
| 5,687.5 |
|
|
| 6,197.2 |
|
|
| (509.7 | ) |
|
| (8 | %) | |
Product purchases |
|
| 1,663.1 |
|
|
|
| 1,222.7 |
|
|
|
| 440.4 |
|
|
| 36 | % |
|
|
| 4,737.8 |
|
|
|
| 3,378.9 |
|
|
| 1,358.9 |
|
|
| 40 | % |
| 1,303.2 |
|
|
| 1,328.1 |
|
|
| (24.9 | ) |
|
| (2 | %) |
|
| 3,346.8 |
|
|
| 4,415.7 |
|
|
| (1,068.9 | ) |
|
| (24 | %) | |
Gross margin (1) |
|
| 468.7 |
|
|
|
| 429.6 |
|
|
|
| 39.1 |
|
|
| 9 | % |
|
|
| 1,374.3 |
|
|
|
| 1,299.5 |
|
|
| 74.8 |
|
|
| 6 | % |
| 811.9 |
|
|
| 574.4 |
|
|
| 237.5 |
|
|
| 41 | % |
|
| 2,340.7 |
|
|
| 1,781.5 |
|
|
| 559.2 |
|
|
| 31 | % | |
Operating expenses |
|
| 155.5 |
|
|
|
| 143.0 |
|
|
|
| 12.5 |
|
|
| 9 | % |
|
|
| 462.6 |
|
|
|
| 413.9 |
|
|
| 48.7 |
|
|
| 12 | % |
| 181.9 |
|
|
| 200.2 |
|
|
| (18.3 | ) |
|
| (9 | %) |
|
| 565.1 |
|
|
| 600.7 |
|
|
| (35.6 | ) |
|
| (6 | %) | |
Operating margin (1) |
|
| 313.2 |
|
|
|
| 286.6 |
|
|
|
| 26.6 |
|
|
| 9 | % |
|
|
| 911.7 |
|
|
|
| 885.6 |
|
|
| 26.1 |
|
|
| 3 | % |
| 630.0 |
|
|
| 374.2 |
|
|
| 255.8 |
|
|
| 68 | % |
|
| 1,775.6 |
|
|
| 1,180.8 |
|
|
| 594.8 |
|
|
| 50 | % | |
Depreciation and amortization expense |
|
| 208.3 |
|
|
|
| 184.0 |
|
|
|
| 24.3 |
|
|
| 13 | % |
|
|
| 602.8 |
|
|
|
| 563.6 |
|
|
| 39.2 |
|
|
| 7 | % |
| 203.7 |
|
|
| 244.3 |
|
|
| (40.6 | ) |
|
| (17 | %) |
|
| 647.3 |
|
|
| 718.9 |
|
|
| (71.6 | ) |
|
| (10 | %) | |
General and administrative expense |
|
| 46.6 |
|
|
|
| 44.0 |
|
|
|
| 2.6 |
|
|
| 6 | % |
|
|
| 139.4 |
|
|
|
| 132.3 |
|
|
| 7.1 |
|
|
| 5 | % |
| 56.3 |
|
|
| 65.6 |
|
|
| (9.3 | ) |
|
| (14 | %) |
|
| 171.7 |
|
|
| 212.3 |
|
|
| (40.6 | ) |
|
| (19 | %) | |
Impairment of property, plant and equipment |
|
| 378.0 |
|
|
|
| — |
|
|
|
| 378.0 |
|
|
| — |
|
|
|
| 378.0 |
|
|
|
| — |
|
|
| 378.0 |
|
|
| — |
| ||||||||||||||||||||||||||||||||
Impairment of goodwill |
|
| — |
|
|
|
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| — |
|
|
|
| 24.0 |
|
|
| (24.0 | ) |
|
| (100 | %) | ||||||||||||||||||||||||||||||||
Impairment of long-lived assets |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,442.8 |
|
|
| — |
|
|
| 2,442.8 |
|
|
| — |
| |||||||||||||||||||||||||||||||||||||
Other operating (income) expense |
|
| 0.6 |
|
|
|
| 4.9 |
|
|
|
| (4.3 | ) |
|
| (88 | %) |
|
|
|
| 17.2 |
|
|
|
| 6.1 |
|
|
| 11.1 |
|
|
| 182 | % |
| 72.2 |
|
|
| 18.4 |
|
|
| 53.8 |
|
|
| 292 | % |
|
| 73.8 |
|
|
| 21.7 |
|
|
| 52.1 |
|
|
| 240 | % |
Income from operations |
|
| (320.3 | ) |
|
|
| 53.7 |
|
|
|
| (374.0 | ) |
| NM |
|
|
|
| (225.7 | ) |
|
|
| 159.6 |
|
|
| (385.3 | ) |
|
| (241 | %) | |||||||||||||||||||||||||||||||||
Income (loss) from operations |
| 297.8 |
|
|
| 45.9 |
|
|
| 251.9 |
|
| NM |
|
|
| (1,560.0 | ) |
|
| 227.9 |
|
|
| (1,787.9 | ) |
| NM |
| |||||||||||||||||||||||||||||||||||||||
Interest expense, net |
|
| (51.9 | ) |
|
|
| (57.9 | ) |
|
|
| 6.0 |
|
|
| 10 | % |
|
|
| (169.5 | ) |
|
|
| (171.2 | ) |
|
| 1.7 |
|
|
| 1 | % |
| (94.9 | ) |
|
| (84.2 | ) |
|
| (10.7 | ) |
|
| 13 | % |
|
| (283.0 | ) |
|
| (229.2 | ) |
|
| (53.8 | ) |
|
| 23 | % | |
Equity earnings (loss) |
|
| 0.2 |
|
|
|
| (2.2 | ) |
|
|
| 2.4 |
|
|
| 109 | % |
|
|
| (16.6 | ) |
|
|
| (11.4 | ) |
|
| (5.2 | ) |
|
| 46 | % |
| 18.6 |
|
|
| 10.0 |
|
|
| 8.6 |
|
|
| 86 | % |
|
| 54.1 |
|
|
| 15.9 |
|
|
| 38.2 |
|
|
| 240 | % | |
Gain (loss) from financing activities |
|
| — |
|
|
|
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| (10.7 | ) |
|
|
| 21.4 |
|
|
| (32.1 | ) |
|
| (150 | %) |
| (13.7 | ) |
|
| — |
|
|
| (13.7 | ) |
|
| — |
|
|
| 47.4 |
|
|
| (1.4 | ) |
|
| 48.8 |
|
| NM |
| ||
Gain (loss) from sale of equity-method investment |
| — |
|
|
| 65.8 |
|
|
| (65.8 | ) |
|
| (100 | %) |
|
| — |
|
|
| 65.8 |
|
|
| (65.8 | ) |
|
| (100 | %) | |||||||||||||||||||||||||||||||||||||
Change in contingent considerations |
|
| 126.8 |
|
|
|
| 0.3 |
|
|
|
| 126.5 |
|
| NM |
|
|
|
| 125.6 |
|
|
|
| 0.3 |
|
|
| 125.3 |
|
| NM |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (8.8 | ) |
|
| 8.8 |
|
|
| 100 | % | |||
Other income (expense), net |
|
| 0.2 |
|
|
|
| 1.0 |
|
|
|
| (0.8 | ) |
|
| (80 | %) |
|
|
| (2.7 | ) |
|
|
| 0.8 |
|
|
| (3.5 | ) |
| NM |
| |||||||||||||||||||||||||||||||||
Income tax (expense) benefit |
|
| — |
|
|
|
| (1.0 | ) |
|
|
| 1.0 |
|
|
| 100 | % |
|
|
| 4.2 |
|
|
|
| — |
|
|
| 4.2 |
|
|
| — |
| ||||||||||||||||||||||||||||||||
Other, net |
| 1.3 |
|
|
| — |
|
|
| 1.3 |
|
|
| — |
|
|
| 2.0 |
|
|
| — |
|
|
| 2.0 |
|
|
| — |
| |||||||||||||||||||||||||||||||||||||
Net income (loss) |
|
| (245.0 | ) |
|
|
| (6.1 | ) |
|
|
| (238.9 | ) |
| NM |
|
|
|
| (295.4 | ) |
|
|
| (0.5 | ) |
|
| (294.9 | ) |
| NM |
|
| 209.1 |
|
|
| 37.5 |
|
|
| 171.6 |
|
| NM |
|
|
| (1,739.5 | ) |
|
| 70.2 |
|
|
| (1,809.7 | ) |
| NM |
| |||||
Less: Net income attributable to noncontrolling interests |
|
| 9.7 |
|
|
|
| 4.7 |
|
|
|
| 5.0 |
|
|
| 106 | % |
|
|
| 25.9 |
|
|
|
| 13.5 |
|
|
| 12.4 |
|
|
| 92 | % | ||||||||||||||||||||||||||||||||
Less: Net income (loss) attributable to noncontrolling interests |
| 100.1 |
|
|
| 76.6 |
|
|
| 23.5 |
|
|
| 31 | % |
|
| 108.1 |
|
|
| 144.3 |
|
|
| (36.2 | ) |
|
| (25 | %) | |||||||||||||||||||||||||||||||||||||
Net income (loss) attributable to Targa Resources Partners LP |
| $ | (254.7 | ) |
|
| $ | (10.8 | ) |
|
| $ | (243.9 | ) |
| NM |
|
|
| $ | (321.3 | ) |
|
| $ | (14.0 | ) |
| $ | (307.3 | ) |
| NM |
| $ | 109.0 |
|
| $ | (39.1 | ) |
| $ | 148.1 |
|
| NM |
|
| $ | (1,847.6 | ) |
| $ | (74.1 | ) |
| $ | (1,773.5 | ) |
| NM |
| |||||
Financial and operating data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||
Financial data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
| $ | 269.6 |
|
|
| $ | 240.3 |
|
|
| $ | 29.3 |
|
|
| 12 | % |
|
|
| $ | 789.6 |
|
|
| $ | 753.2 |
|
| $ | 36.4 |
|
|
| 5 | % | $ | 404.9 |
|
| $ | 337.8 |
|
| $ | 67.1 |
|
|
| 20 | % |
| $ | 1,157.7 |
|
| $ | 932.6 |
|
| $ | 225.1 |
|
|
| 24 | % |
Capital expenditures |
|
| 378.7 |
|
|
|
| 134.6 |
|
|
|
| 244.1 |
|
|
| 181 | % |
|
|
| 987.7 |
|
|
|
| 426.5 |
|
|
| 561.2 |
|
|
| 132 | % | ||||||||||||||||||||||||||||||||
Business acquisition (2) |
|
| — |
|
|
|
| — |
|
|
|
| — |
|
|
| — |
|
|
|
|
| 987.1 |
|
|
|
| — |
|
|
| 987.1 |
|
|
| — |
| |||||||||||||||||||||||||||||||
Operating statistics: (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||
Crude oil gathered, Badlands, MBbl/d |
|
| 108.7 |
|
|
|
| 103.9 |
|
|
|
| 4.8 |
|
|
| 5 | % |
|
|
|
| 111.6 |
|
|
|
| 105.7 |
|
|
| 5.9 |
|
|
| 6 | % | |||||||||||||||||||||||||||||||
Crude oil gathered, Permian, MBbl/d (4) |
|
| 35.7 |
|
|
|
| — |
|
|
|
| 35.7 |
|
|
| — |
|
|
|
|
| 24.6 |
|
|
|
| — |
|
|
| 24.6 |
|
|
| — |
| |||||||||||||||||||||||||||||||
Plant natural gas inlet, MMcf/d (5)(6) |
|
| 3,621.4 |
|
|
|
| 3,356.6 |
|
|
|
| 264.8 |
|
|
| 8 | % |
|
|
| 3,418.5 |
|
|
|
| 3,422.3 |
|
|
| (3.8 | ) |
|
| — |
| ||||||||||||||||||||||||||||||||
Gross NGL production, MBbl/d |
|
| 346.2 |
|
|
|
| 310.4 |
|
|
|
| 35.8 |
|
|
| 12 | % |
|
|
|
| 318.9 |
|
|
|
| 305.4 |
|
|
| 13.5 |
|
|
| 4 | % | |||||||||||||||||||||||||||||||
Export volumes, MBbl/d (7) |
|
| 154.5 |
|
|
|
| 156.7 |
|
|
|
| (2.2 | ) |
|
| (1 | %) |
|
|
|
| 175.5 |
|
|
|
| 173.0 |
|
|
| 2.5 |
|
|
| 1 | % | |||||||||||||||||||||||||||||||
Natural gas sales, BBtu/d (6)(8) |
|
| 2,054.1 |
|
|
|
| 1,993.0 |
|
|
|
| 61.1 |
|
|
| 3 | % |
|
|
| 1,942.5 |
|
|
|
| 1,975.4 |
|
|
| (32.9 | ) |
|
| (2 | %) | ||||||||||||||||||||||||||||||||
NGL sales, MBbl/d (8) |
|
| 497.6 |
|
|
|
| 497.3 |
|
|
|
| 0.3 |
|
|
| — |
|
|
|
| 501.6 |
|
|
|
| 520.6 |
|
|
| (19.0 | ) |
|
| (4 | %) | ||||||||||||||||||||||||||||||||
Condensate sales, MBbl/d |
|
| 11.4 |
|
|
|
| 10.0 |
|
|
|
| 1.4 |
|
|
| 14 | % |
|
|
| 11.5 |
|
|
|
| 10.3 |
|
|
| 1.2 |
|
|
| 12 | % |
(1) | Gross margin, operating margin, and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.
Three Months Ended September 30, 20172020 Compared to Three Months Ended September 30, 20162019
The increase in commodity sales was primarily due toreflects higher commodityNGL and natural gas prices ($443.3133.5 million), higher NGL, condensate and petroleum products volumes ($100.7 million) and increased volumesthe favorable impact of hedges ($40.0171.0 million), partially offset by the impact of hedge settlementslower crude marketing and natural gas volumes ($10.5128.9 million). Fee-based and other revenues increasedlower condensate and petroleum product prices ($29.6 million).
The decrease in fees from midstream services is primarily due to highernew commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, and lower gas processing fees.volumes, partially offset by increased export and terminaling and storage volumes.
The increasedecrease in product purchases was primarily due toreflects lower crude marketing volumes associated with the impact of higher commodity prices and increased volumes.
In the third quarter of 2017, we experienced limited impacts to our operations as a result of Hurricane Harvey. We incurred: (i) flooding at our Mont Belvieu facilities that resulted in temporary constraints on the receipt of NGLs and the temporary removal of fractionators from service at CBF, resulting in increased levels of mixed NGLs in storage and (ii) the shut-in of our Galena Park Marine Terminal for approximately one week due to the closuresale of the Houston Ship Channel. Our operating margin for the three months ended September 30, 2017,Delaware crude system, which was reducedeffective December 1, 2019, and lower natural gas volumes, partially offset by approximately $10 million as a result of Hurricane Harvey, comprised of the impact on the Mont Belvieuhigher NGL and Galena Park Marine Terminal facilities along with lost operating margin associated with temporary production disruptions for a limited number of our producer and downstream customers. We expect to recover approximately $7 million of the reduced operating margin during the fourth quarter of 2017 when the additional stored volumes of mixed NGLs are fractionated and sold. No property insurance claims are expected as a result of the storm as damage to our facilities was minimal. Business interruption insurance claims related to the storm are expected to be minimal.natural gas prices.
The higherHigher operating margin and gross margin in 2017 reflects2020 reflect increased segment margin results for Gathering and Processing partially offset by decreasedand Logistics and Marketing segment margins. Operating expenses increased compared to 2016 due to the impact of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement of operations of the Raptor Plant at SouthTX in the Gathering and Processing segment, and higher labor, repairs and maintenance expense in the Logistics and Marketing segment.Transportation. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.
Depreciation and amortization expense increaseddecreased primarily due to a lower depreciable base associated with assets that were impaired during the impactfirst quarter of 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including Train 7 and the additional processing plants and associated infrastructure in the Permian Acquisition and other growth investments.Basin.
General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs.
Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of our assets in Channelview, Texas in connection with the October 2020 Saleand write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts.
Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.
The increase in equity earnings is primarily due to higher compensationearnings from our investments in GCX and benefits,Little Missouri 4 LLC (“Little Missouri 4”), partially offset by lower professional services.
The impairment of property, plant and equipment in 2017 reflects an impairment as of September 30, 2017 of gas processing facilities and gathering systems associated with our North Texas operations in the Gathering and Processing segment. The impairment is a result of our current assessment that forecasted undiscounted future net cash flowsearnings from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Given the current price environment, Targa is projecting a continuing decline in natural gas production across the Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins.
Net interest expense decreased primarily due to the impact of lower average outstanding borrowings during 2017, partially offset by higher non-cash interest expense related to the mandatorily redeemable preferred interests that is revalued quarterly at the estimated redemption value as of the reporting dateGulf Coast Fractionators LP (“GCF”).
During 2017,the third quarter of 2020, we recorded other incomeredeemed the 6¾% Senior Notes due 2024, resulting in a $13.7 million net loss from financing activities.
During the third quarter of $126.8 million resulting from2019, we closed on the change in the fair valuesale of contingent considerations, substantially all of which was due to the reduction in fair value as of September 30, 2017 of the Permian Acquisition contingent consideration liability, which is based on a multiple of gross margin realized during the first two annual periods after the acquisition date. The decrease in fair value was primarily related to reductions in actual and forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date. Such changes in estimated fair value of the contingent consideration are attributable to events and circumstancesan equity-method investment that occurred after the acquisition date, and as such are recognized in earnings. The fair value of the contingent consideration represents our current view of the future payment amounts, and may decrease or increase until the settlement dates, resultingresulted in the recognition of additional other income (expense).a gain of $65.8 million.
Net income attributable to noncontrolling interests was higher in 20172020 primarily due to increased earnings at our joint ventures as compared with 2016.income allocated to noncontrolling interest holders in the Grand Prix Joint Venture, Targa GCX Pipeline LLC (“GCX DevCo JV”) and the Centrahoma Joint Venture.
Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019
The increasedecrease in commodity sales was primarily due to higher commodityreflects lower NGL, condensate, natural gas and petroleum product prices ($1,600.91,112.5 million) and increased petroleum products and condensatelower crude marketing volumes ($44.0254.7 million), partially offset by decreasedhigher NGL, andcondensate, natural gas salesand petroleum product volumes ($126.0664.3 million), the favorable impact of hedges ($345.1 million) and the impact of hedge settlementshigher crude marketing prices ($48.73.8 million). Fee-based and other revenues decreased
The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, and lower export fees,gas processing volumes, partially offset by increases in gas processingincreased export and crude gathering fees.terminaling and storage volumes.
The increasedecrease in product purchases reflects lower NGL, condensate, natural gas and petroleum product prices, as well as lower crude marketing volumes associated with the sale of the Delaware crude system, which was primarily due to the impact of higher commodity prices,effective December 1, 2019, partially offset by decreasedhigher NGL, condensate, natural gas and petroleum product volumes.
In the third quarter of 2017, we experienced limited impacts to our operations as a result of Hurricane Harvey. Our operating margin for the nine months ended September 30, 2017, was reduced by approximately $10 million as a result of Hurricane Harvey, comprised
of the impact on the Mont Belvieu and Galena Park Marine Terminal facilities along with lost operating margin associated with temporary production disruptions for a limited number of our producer and chemical customers. We expect to recover approximately $7 million of the reduced operating margin during the fourth quarter of 2017 when the additional stored volumes of mixed NGLs are fractionated and sold.
The higherHigher operating margin and gross margin in 2017 reflects2020 reflect increased segment margin results for Gathering and Processing partially offset by decreasedand Logistics and Marketing segment margins. Operating expenses increased compared to 2016 due to the impact of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement of operations of the Raptor Plant at SouthTX in the Gathering and Processing segment, and higher fuel and power that is largely passed through in the Logistics and Marketing segment.Transportation. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.
Depreciation and amortization expense increaseddecreased primarily due to a lower depreciable base associated with assets that were impaired during the impactfirst quarter of the March 2017 Permian Acquisition2020 and the impactsale of otherthe Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth investments,capital projects placed in service, including CBF Train 5 that went into service7 and the additional processing plants and associated infrastructure in the second quarter of 2016 and the Raptor Plant at SouthTX that went into service in the second quarter of 2017.Permian Basin.
General and administrative expense increased primarilydecreased due to highercost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by lower professional services.an increase in insurance costs.
The impairment of property, plant and equipment in 2017 reflects ancharge is primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our North Texas operations in the Gathering and Processing segment (described above).
In the first quarter of 2016, we recognized a $24.0 million adjustment to a provisional2020 associated with our Mid-Continent operations and full impairment of goodwill recordedour Coastal operations - all of which are in our Gathering and Processing segment. Based on then-current market conditions, our first quarter impairment assessment projected further decline in natural gas production across the Mid-Continent and Gulf of Mexico. We did not recognize any impairments of long-lived assets during the nine months ended September 30, 2019. We may identify additional triggering events in the fourth quarterfuture, which will require additional evaluations of 2015 related to goodwill acquiredthe recoverability of the carrying value of our long-lived assets and may result in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers’).future impairments.
Other operating (income) expense in 2017 is2020 consisted primarily due toof a loss associated with the reduction in the carrying value of our ownership interestassets in the Venice Gathering SystemChannelview, Texas in connection with the April 2017 sale. October 2020 Sale and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 20162019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts.
Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.
The increase in equity earnings is primarily due to the loss on decommissioning two storage wells athigher earnings from our Hattiesburg facilityinvestments in GCX and an acid gas injection well at our Versado facility.
Net interest expense in 2017 decreased as compared with 2016 primarily due to lower average outstanding borrowings during 2017,Little Missouri 4, partially offset by higher non-cashlower earnings from GCF.
During the nine months ended September 30, 2020, we repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024, paying $831.0 million plus accrued interest expense related to the mandatorily redeemable preferred interests that is revalued quarterly at the estimated redemption value asrepurchase $883.4 million of the reporting date.notes, resulting in a $47.4 million net gain from financing activities.
Higher equity losses in 2017 reflects a $12.0 million loss provision due toDuring the impairmentthird quarter of our2019, we closed on the sale of an equity-method investment that resulted in the T2 EF Cogen joint venture, partially offset by increased equity earnings at Gulf Coast Fractionators.
During 2017, we recorded a loss from financing activitiesrecognition of $10.7 million on the redemption of the outstanding 6⅜% Senior Notes, whereas in 2016 we recorded a gain of $21.4 million on open market debt repurchases.
During 2017, we recorded other income of $125.6 million resulting from the change in the fair value of contingent considerations, substantially all of which was due to the reduction in fair value as of September 30, 2017 of the Permian Acquisition contingent consideration liability.
The increase in income tax benefit was primarily due to a Texas Margin Tax refund in the first quarter of 2017.$65.8 million.
Net income attributable to noncontrolling interests was higherlower in 20172020 primarily due to our October 2016 acquisitionthe allocation of impairment losses recognized during the 37%first quarter of 2020 to noncontrolling interest of Versado that we did not already own. Further, earnings at our joint ventures increased as compared with 2016.holders, partially offset by higher income allocated to noncontrolling interest holders in Targa Badlands LLC (“Targa Badlands”), the DevCo Joint Ventures and the Grand Prix Joint Venture.
Results of Operations—By Reportable Segment
Our operating margins by reportable segment are:
|
| Gathering and Processing |
|
| Logistics and Marketing |
|
| Other |
|
| Total |
| ||||
| (In millions) |
| ||||||||||||||
Three Months Ended: |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
September 30, 2017 |
| $ | 198.3 |
|
| $ | 115.9 |
|
| $ | (1.0 | ) |
| $ | 313.2 |
|
September 30, 2016 |
|
| 149.4 |
|
|
| 126.0 |
|
|
| 11.2 |
|
|
| 286.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
| $ | 549.3 |
|
| $ | 358.5 |
|
| $ | 3.9 |
|
| $ | 911.7 |
|
September 30, 2016 |
|
| 404.1 |
|
|
| 424.6 |
|
|
| 56.9 |
|
|
| 885.6 |
|
| Gathering and Processing |
|
| Logistics and Transportation |
|
| Other |
|
| Consolidated Operating Margin |
| ||||||||
| (In millions) |
| |||||||||||||||||
Three Months Ended: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2020 | $ |
| 261.0 |
|
| $ |
| 280.4 |
|
| $ |
| 88.6 |
|
| $ |
| 630.0 |
|
September 30, 2019 |
|
| 246.5 |
|
|
|
| 228.9 |
|
|
|
| (101.2 | ) |
|
|
| 374.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2020 | $ |
| 753.7 |
|
| $ |
| 806.0 |
|
| $ |
| 215.9 |
|
| $ |
| 1,775.6 |
|
September 30, 2019 |
|
| 716.8 |
|
|
|
| 565.0 |
|
|
|
| (101.1 | ) |
|
|
| 1,180.7 |
|
Gathering and Processing Segment
| Three Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
| ||||||||||||||
| 2017 |
|
| 2016 |
|
| 2017 vs. 2016 |
|
| 2017 |
|
| 2016 |
|
|
| 2017 vs. 2016 |
| |||||||||||||||||||
Gross margin | $ |
| 289.7 |
|
| $ |
| 231.7 |
|
| $ |
| 58.0 |
|
|
| 25 | % |
| $ |
| 817.1 |
|
| $ |
| 648.0 |
|
| $ |
| 169.1 |
|
|
| 26 | % |
Operating expenses |
|
| 91.4 |
|
|
|
| 82.3 |
|
|
|
| 9.1 |
|
|
| 11 | % |
|
|
| 267.8 |
|
|
|
| 243.9 |
|
|
|
| 23.9 |
|
|
| 10 | % |
Operating margin | $ |
| 198.3 |
|
| $ |
| 149.4 |
|
| $ |
| 48.9 |
|
|
| 33 | % |
| $ |
| 549.3 |
|
| $ |
| 404.1 |
|
| $ |
| 145.2 |
|
|
| 36 | % |
Operating statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU (4) |
|
| 324.6 |
|
|
|
| 262.5 |
|
|
|
| 62.1 |
|
|
| 24 | % |
|
|
| 304.1 |
|
|
|
| 255.1 |
|
|
|
| 49.0 |
|
|
| 19 | % |
WestTX |
|
| 607.5 |
|
|
|
| 506.0 |
|
|
|
| 101.5 |
|
|
| 20 | % |
|
|
| 560.8 |
|
|
|
| 480.8 |
|
|
|
| 80.0 |
|
|
| 17 | % |
Total Permian Midland |
|
| 932.1 |
|
|
|
| 768.5 |
|
|
|
| 163.6 |
|
|
|
|
|
|
|
| 864.9 |
|
|
|
| 735.9 |
|
|
|
| 129.0 |
|
|
|
|
|
Sand Hills (4) |
|
| 193.0 |
|
|
|
| 140.9 |
|
|
|
| 52.1 |
|
|
| 37 | % |
|
|
| 171.6 |
|
|
|
| 142.6 |
|
|
|
| 29.0 |
|
|
| 20 | % |
Versado |
|
| 210.9 |
|
|
|
| 180.6 |
|
|
|
| 30.3 |
|
|
| 17 | % |
|
|
| 202.0 |
|
|
|
| 176.5 |
|
|
|
| 25.5 |
|
|
| 14 | % |
Total Permian Delaware |
|
| 403.9 |
|
|
|
| 321.5 |
|
|
|
| 82.4 |
|
|
|
|
|
|
|
| 373.6 |
|
|
|
| 319.1 |
|
|
|
| 54.5 |
|
|
|
|
|
Total Permian |
|
| 1,336.0 |
|
|
|
| 1,090.0 |
|
|
|
| 246.0 |
|
|
|
|
|
|
|
| 1,238.5 |
|
|
|
| 1,055.0 |
|
|
|
| 183.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
| 330.1 |
|
|
|
| 218.0 |
|
|
|
| 112.1 |
|
|
| 51 | % |
|
|
| 242.1 |
|
|
|
| 219.7 |
|
|
|
| 22.4 |
|
|
| 10 | % |
North Texas |
|
| 261.8 |
|
|
|
| 315.2 |
|
|
|
| (53.4 | ) |
|
| (17 | %) |
|
|
| 273.7 |
|
|
|
| 323.4 |
|
|
|
| (49.7 | ) |
|
| (15 | %) |
SouthOK |
|
| 515.2 |
|
|
|
| 469.8 |
|
|
|
| 45.4 |
|
|
| 10 | % |
|
|
| 478.5 |
|
|
|
| 466.1 |
|
|
|
| 12.4 |
|
|
| 3 | % |
WestOK |
|
| 367.1 |
|
|
|
| 434.4 |
|
|
|
| (67.3 | ) |
|
| (15 | %) |
|
|
| 382.5 |
|
|
|
| 455.6 |
|
|
|
| (73.1 | ) |
|
| (16 | %) |
Total Central |
|
| 1,474.2 |
|
|
|
| 1,437.4 |
|
|
|
| 36.8 |
|
|
|
|
|
|
|
| 1,376.8 |
|
|
|
| 1,464.8 |
|
|
|
| (88.0 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (5) |
|
| 60.9 |
|
|
|
| 53.8 |
|
|
|
| 7.1 |
|
|
| 13 | % |
|
|
| 53.1 |
|
|
|
| 52.9 |
|
|
|
| 0.2 |
|
|
| — |
|
Total Field |
|
| 2,871.1 |
|
|
|
| 2,581.2 |
|
|
|
| 289.9 |
|
|
|
|
|
|
|
| 2,668.4 |
|
|
|
| 2,572.7 |
|
|
|
| 95.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
| 750.5 |
|
|
|
| 775.5 |
|
|
|
| (25.0 | ) |
|
| (3 | %) |
|
|
| 750.1 |
|
|
|
| 849.7 |
|
|
|
| (99.6 | ) |
|
| (12 | %) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
| 3,621.6 |
|
|
|
| 3,356.7 |
|
|
|
| 264.9 |
|
|
| 8 | % |
|
|
| 3,418.5 |
|
|
|
| 3,422.4 |
|
|
|
| (3.9 | ) |
|
| — |
|
Gross NGL production, MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU (4) |
|
| 38.7 |
|
|
|
| 32.8 |
|
|
|
| 5.9 |
|
|
| 18 | % |
|
|
| 36.6 |
|
|
|
| 31.4 |
|
|
|
| 5.2 |
|
|
| 17 | % |
WestTX |
|
| 84.1 |
|
|
|
| 67.6 |
|
|
|
| 16.5 |
|
|
| 24 | % |
|
|
| 75.2 |
|
|
|
| 60.7 |
|
|
|
| 14.5 |
|
|
| 24 | % |
Total Permian Midland |
|
| 122.8 |
|
|
|
| 100.4 |
|
|
|
| 22.4 |
|
|
|
|
|
|
|
| 111.8 |
|
|
|
| 92.1 |
|
|
|
| 19.7 |
|
|
|
|
|
Sand Hills (4) |
|
| 21.0 |
|
|
|
| 15.2 |
|
|
|
| 5.8 |
|
|
| 38 | % |
|
|
| 18.6 |
|
|
|
| 15.0 |
|
|
|
| 3.6 |
|
|
| 24 | % |
Versado |
|
| 25.3 |
|
|
|
| 21.8 |
|
|
|
| 3.5 |
|
|
| 16 | % |
|
|
| 23.8 |
|
|
|
| 21.3 |
|
|
|
| 2.5 |
|
|
| 12 | % |
Total Permian Delaware |
|
| 46.3 |
|
|
|
| 37.0 |
|
|
|
| 9.3 |
|
|
|
|
|
|
|
| 42.4 |
|
|
|
| 36.3 |
|
|
|
| 6.1 |
|
|
|
|
|
Total Permian |
|
| 169.1 |
|
|
|
| 137.4 |
|
|
|
| 31.7 |
|
|
|
|
|
|
|
| 154.2 |
|
|
|
| 128.4 |
|
|
|
| 25.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
| 35.4 |
|
|
|
| 20.9 |
|
|
|
| 14.5 |
|
|
| 69 | % |
|
|
| 25.2 |
|
|
|
| 25.1 |
|
|
|
| 0.1 |
|
|
| — |
|
North Texas |
|
| 29.3 |
|
|
|
| 36.2 |
|
|
|
| (6.9 | ) |
|
| (19 | %) |
|
|
| 30.8 |
|
|
|
| 36.3 |
|
|
|
| (5.5 | ) |
|
| (15 | %) |
SouthOK |
|
| 42.7 |
|
|
|
| 42.4 |
|
|
|
| 0.3 |
|
|
| 1 | % |
|
|
| 40.7 |
|
|
|
| 39.3 |
|
|
|
| 1.4 |
|
|
| 4 | % |
WestOK |
|
| 20.7 |
|
|
|
| 27.2 |
|
|
|
| (6.5 | ) |
|
| (24 | %) |
|
|
| 22.3 |
|
|
|
| 27.9 |
|
|
|
| (5.6 | ) |
|
| (20 | %) |
Total Central |
|
| 128.1 |
|
|
|
| 126.7 |
|
|
|
| 1.4 |
|
|
|
|
|
|
|
| 119.0 |
|
|
|
| 128.6 |
|
|
|
| (9.6 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| �� |
|
|
|
|
|
|
|
|
Badlands |
|
| 9.0 |
|
|
|
| 7.8 |
|
|
|
| 1.2 |
|
|
| 15 | % |
|
|
| 7.4 |
|
|
|
| 7.5 |
|
|
|
| (0.1 | ) |
|
| (1 | %) |
Total Field |
|
| 306.2 |
|
|
|
| 271.9 |
|
|
|
| 34.3 |
|
|
|
|
|
|
|
| 280.6 |
|
|
|
| 264.5 |
|
|
|
| 16.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
| 40.0 |
|
|
|
| 38.6 |
|
|
|
| 1.4 |
|
|
| 4 | % |
|
|
| 38.2 |
|
|
|
| 41.0 |
|
|
|
| (2.8 | ) |
|
| (7 | %) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
| 346.2 |
|
|
|
| 310.5 |
|
|
|
| 35.7 |
|
|
| 11 | % |
|
|
| 318.8 |
|
|
|
| 305.5 |
|
|
|
| 13.3 |
|
|
| 4 | % |
Crude oil gathered, Badlands, MBbl/d |
|
| 108.7 |
|
|
|
| 103.9 |
|
|
|
| 4.8 |
|
|
| 5 | % |
|
|
| 111.6 |
|
|
|
| 105.7 |
|
|
|
| 5.9 |
|
|
| 6 | % |
Crude oil gathered, Permian, MBbl/d (4) |
|
| 35.7 |
|
|
|
| — |
|
|
|
| 35.7 |
|
|
| — |
|
|
|
| 24.6 |
|
|
|
| — |
|
|
|
| 24.6 |
|
|
| — |
|
Natural gas sales, BBtu/d (3) |
|
| 1,738.5 |
|
|
|
| 1,617.6 |
|
|
|
| 120.9 |
|
|
| 7 | % |
|
|
| 1,647.8 |
|
|
|
| 1,636.8 |
|
|
|
| 11.0 |
|
|
| 1 | % |
NGL sales, MBbl/d |
|
| 244.4 |
|
|
|
| 248.4 |
|
|
|
| (4.0 | ) |
|
| (2 | %) |
|
|
| 240.4 |
|
|
|
| 241.3 |
|
|
|
| (0.9 | ) |
|
| - |
|
Condensate sales, MBbl/d |
|
| 11.4 |
|
|
|
| 9.7 |
|
|
|
| 1.7 |
|
|
| 18 | % |
|
|
| 11.4 |
|
|
|
| 10.0 |
|
|
|
| 1.4 |
|
|
| 14 | % |
Average realized prices (6): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
| 2.58 |
|
|
|
| 2.49 |
|
|
|
| 0.09 |
|
|
| 4 | % |
|
|
| 2.71 |
|
|
|
| 1.96 |
|
|
|
| 0.75 |
|
|
| 38 | % |
NGL, $/gal |
|
| 0.56 |
|
|
|
| 0.36 |
|
|
|
| 0.20 |
|
|
| 56 | % |
|
|
| 0.51 |
|
|
|
| 0.33 |
|
|
|
| 0.18 |
|
|
| 55 | % |
Condensate, $/Bbl |
|
| 42.69 |
|
|
|
| 38.29 |
|
|
|
| 4.40 |
|
|
| 11 | % |
|
|
| 43.42 |
|
|
|
| 34.18 |
|
|
|
| 9.24 |
|
|
| 27 | % |
| Three Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
| ||||||||||||||
| 2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
|
| 2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
| ||||||||||||||||||||
| (In millions, except operating statistics and price amounts) |
| |||||||||||||||||||||||||||||||||||
Gross margin | $ |
| 362.9 |
|
| $ |
| 366.7 |
|
| $ |
| (3.8 | ) |
|
| (1 | %) |
| $ |
| 1,071.4 |
|
| $ |
| 1,092.0 |
|
| $ |
| (20.6 | ) |
|
| (2 | %) |
Operating expenses |
|
| 101.9 |
|
|
|
| 120.2 |
|
|
|
| (18.3 | ) |
|
| (15 | %) |
|
|
| 317.7 |
|
|
|
| 375.2 |
|
|
|
| (57.5 | ) |
|
| (15 | %) |
Operating margin | $ |
| 261.0 |
|
| $ |
| 246.5 |
|
| $ |
| 14.5 |
|
|
| 6 | % |
| $ |
| 753.7 |
|
| $ |
| 716.8 |
|
| $ |
| 36.9 |
|
|
| 5 | % |
Operating statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
| 1,811.5 |
|
|
|
| 1,513.9 |
|
|
|
| 297.6 |
|
|
| 20 | % |
|
|
| 1,722.1 |
|
|
|
| 1,421.3 |
|
|
|
| 300.8 |
|
|
| 21 | % |
Permian Delaware |
|
| 758.1 |
|
|
|
| 629.4 |
|
|
|
| 128.7 |
|
|
| 20 | % |
|
|
| 712.4 |
|
|
|
| 552.2 |
|
|
|
| 160.2 |
|
|
| 29 | % |
Total Permian |
|
| 2,569.6 |
|
|
|
| 2,143.3 |
|
|
|
| 426.3 |
|
|
|
|
|
|
|
| 2,434.5 |
|
|
|
| 1,973.5 |
|
|
|
| 461.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
| 233.6 |
|
|
|
| 328.6 |
|
|
|
| (95.0 | ) |
|
| (29 | %) |
|
|
| 261.5 |
|
|
|
| 335.3 |
|
|
|
| (73.8 | ) |
|
| (22 | %) |
North Texas |
|
| 197.8 |
|
|
|
| 228.2 |
|
|
|
| (30.4 | ) |
|
| (13 | %) |
|
|
| 206.3 |
|
|
|
| 227.6 |
|
|
|
| (21.3 | ) |
|
| (9 | %) |
SouthOK (6) |
|
| 386.9 |
|
|
|
| 590.8 |
|
|
|
| (203.9 | ) |
|
| (35 | %) |
|
|
| 463.3 |
|
|
|
| 606.1 |
|
|
|
| (142.8 | ) |
|
| (24 | %) |
WestOK |
|
| 233.6 |
|
|
|
| 329.2 |
|
|
|
| (95.6 | ) |
|
| (29 | %) |
|
|
| 258.7 |
|
|
|
| 335.2 |
|
|
|
| (76.5 | ) |
|
| (23 | %) |
Total Central |
|
| 1,051.9 |
|
|
|
| 1,476.8 |
|
|
|
| (424.9 | ) |
|
|
|
|
|
|
| 1,189.8 |
|
|
|
| 1,504.2 |
|
|
|
| (314.4 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (7),(8) |
|
| 137.0 |
|
|
|
| 120.8 |
|
|
|
| 16.2 |
|
|
| 13 | % |
|
|
| 136.1 |
|
|
|
| 103.4 |
|
|
|
| 32.7 |
|
|
| 32 | % |
Total Field |
|
| 3,758.5 |
|
|
|
| 3,740.9 |
|
|
|
| 17.6 |
|
|
|
|
|
|
|
| 3,760.4 |
|
|
|
| 3,581.1 |
|
|
|
| 179.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
| 522.8 |
|
|
|
| 764.9 |
|
|
|
| (242.1 | ) |
|
| (32 | %) |
|
|
| 672.9 |
|
|
|
| 779.9 |
|
|
|
| (107.0 | ) |
|
| (14 | %) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
| 4,281.3 |
|
|
|
| 4,505.8 |
|
|
|
| (224.5 | ) |
|
| (5 | %) |
|
|
| 4,433.3 |
|
|
|
| 4,361.0 |
|
|
|
| 72.3 |
|
|
| 2 | % |
NGL production, MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
| 253.0 |
|
|
|
| 216.5 |
|
|
|
| 36.5 |
|
|
| 17 | % |
|
|
| 247.6 |
|
|
|
| 199.8 |
|
|
|
| 47.8 |
|
|
| 24 | % |
Permian Delaware |
|
| 105.3 |
|
|
|
| 82.3 |
|
|
|
| 23.0 |
|
|
| 28 | % |
|
|
| 97.1 |
|
|
|
| 71.4 |
|
|
|
| 25.7 |
|
|
| 36 | % |
Total Permian |
|
| 358.3 |
|
|
|
| 298.8 |
|
|
|
| 59.5 |
|
|
|
|
|
|
|
| 344.7 |
|
|
|
| 271.2 |
|
|
|
| 73.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
| 29.2 |
|
|
|
| 41.5 |
|
|
|
| (12.3 | ) |
|
| (30 | %) |
|
|
| 28.7 |
|
|
|
| 44.0 |
|
|
|
| (15.3 | ) |
|
| (35 | %) |
North Texas |
|
| 23.7 |
|
|
|
| 27.3 |
|
|
|
| (3.6 | ) |
|
| (13 | %) |
|
|
| 24.5 |
|
|
|
| 26.9 |
|
|
|
| (2.4 | ) |
|
| (9 | %) |
SouthOK (6) |
|
| 45.9 |
|
|
|
| 69.5 |
|
|
|
| (23.6 | ) |
|
| (34 | %) |
|
|
| 54.6 |
|
|
|
| 65.4 |
|
|
|
| (10.8 | ) |
|
| (17 | %) |
WestOK |
|
| 19.3 |
|
|
|
| 19.2 |
|
|
|
| 0.1 |
|
|
| 1 | % |
|
|
| 21.2 |
|
|
|
| 22.4 |
|
|
|
| (1.2 | ) |
|
| (5 | %) |
Total Central |
|
| 118.1 |
|
|
|
| 157.5 |
|
|
|
| (39.4 | ) |
|
|
|
|
|
|
| 129.0 |
|
|
|
| 158.7 |
|
|
|
| (29.7 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (8) |
|
| 17.0 |
|
|
|
| 14.0 |
|
|
|
| 3.0 |
|
|
| 21 | % |
|
|
| 16.3 |
|
|
|
| 12.2 |
|
|
|
| 4.1 |
|
|
| 34 | % |
Total Field |
|
| 493.4 |
|
|
|
| 470.3 |
|
|
|
| 23.1 |
|
|
|
|
|
|
|
| 490.0 |
|
|
|
| 442.1 |
|
|
|
| 47.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
| 32.5 |
|
|
|
| 45.4 |
|
|
|
| (12.9 | ) |
|
| (28 | %) |
|
|
| 41.5 |
|
|
|
| 47.0 |
|
|
|
| (5.5 | ) |
|
| (12 | %) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
| 525.9 |
|
|
|
| 515.7 |
|
|
|
| 10.2 |
|
|
| 2 | % |
|
|
| 531.5 |
|
|
|
| 489.1 |
|
|
|
| 42.4 |
|
|
| 9 | % |
Crude oil, Badlands, MBbl/d |
|
| 146.4 |
|
|
|
| 164.3 |
|
|
|
| (17.9 | ) |
|
| (11 | %) |
|
|
| 160.4 |
|
|
|
| 167.0 |
|
|
|
| (6.6 | ) |
|
| (4 | %) |
Crude oil, Permian, MBbl/d (9) |
|
| 44.6 |
|
|
|
| 95.2 |
|
|
|
| (50.6 | ) |
|
| (53 | %) |
|
|
| 45.3 |
|
|
|
| 86.1 |
|
|
|
| (40.8 | ) |
|
| (47 | %) |
Natural gas sales, BBtu/d (3),(10) |
|
| 2,032.3 |
|
|
|
| 2,056.6 |
|
|
|
| (24.3 | ) |
|
| (1 | %) |
|
|
| 2,079.3 |
|
|
|
| 2,011.2 |
|
|
|
| 68.1 |
|
|
| 3 | % |
NGL sales, MBbl/d (3),(10) |
|
| 389.5 |
|
|
|
| 398.0 |
|
|
|
| (8.5 | ) |
|
| (2 | %) |
|
|
| 406.0 |
|
|
|
| 382.4 |
|
|
|
| 23.6 |
|
|
| 6 | % |
Condensate sales, MBbl/d |
|
| 13.6 |
|
|
|
| 11.0 |
|
|
|
| 2.6 |
|
|
| 24 | % |
|
|
| 16.1 |
|
|
|
| 12.2 |
|
|
|
| 3.9 |
|
|
| 32 | % |
Average realized prices - inclusive of hedges (11): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
| 1.34 |
|
|
|
| 1.13 |
|
|
|
| 0.21 |
|
|
| 19 | % |
|
|
| 1.10 |
|
|
|
| 1.31 |
|
|
|
| (0.21 | ) |
|
| (16 | %) |
NGL, $/gal |
|
| 0.29 |
|
|
|
| 0.28 |
|
|
|
| 0.01 |
|
|
| 4 | % |
|
|
| 0.24 |
|
|
|
| 0.35 |
|
|
|
| (0.11 | ) |
|
| (31 | %) |
Condensate, $/Bbl |
|
| 43.49 |
|
|
|
| 50.23 |
|
|
|
| (6.74 | ) |
|
| (13 | %) |
|
|
| 38.56 |
|
|
|
| 49.49 |
|
|
|
| (10.93 | ) |
|
| (22 | %) |
(1) | Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter. |
(2) | Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than Badlands. |
(3) | Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes. |
(4) |
|
|
|
|
|
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
The increase in gross margin was primarily due to higher commodity prices and higher Permian volumes, including those associated with the Permian Acquisition. Field Gathering and Processing inlet volume increases included all areas in the Permian region, as well as SouthTX, Badlands and SouthOK, partially offset by decreases at WestOK and North Texas. The inlet volume decrease for Coastal Gathering and Processing, which generates significantly lower unit margins, partially offset the Field Gathering and Processing inlet volume increase. NGL production and natural gas sales increased primarily due to increased Field Gathering and Processing inlet volumes. The decrease in NGL sales was primarily due to the deferral to the fourth quarter of 2017 of NGL sales impacted by the temporary operational issues related to Hurricane Harvey. Total crude oil gathered volumes increased in the Permian region due to the Permian Acquisition. Total Badlands crude oil gathered volumes and natural gas volumes increased primarily due to system expansions.
The increase in operating expenses was primarily driven by the inclusion of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement in operations of the Raptor Plant at SouthTX.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
The increase in gross margin was primarily due to higher commodity prices and higher Permian volumes including those associated with the Permian Acquisition. Field Gathering and Processing inlet volume increases included all areas in the Permian region, as well as SouthTX and SouthOK, partially offset by decreases at WestOK and North Texas. The inlet volume decrease for Coastal Gathering and Processing, which generates significantly lower unit margins, more than offset the Field Gathering and Processing inlet volume increase. Despite overall lower inlet volumes, NGL production increased primarily due to increased plant recoveries including additional ethane recovery. Third quarter NGL sales were reduced due to the deferral to the fourth quarter of 2017 of NGL sales impacted by the temporary operational issues related to Hurricane Harvey. Natural gas sales increased primarily due to increased Field Gathering and Processing inlet volumes. Total crude oil gathered volumes increased in the Permian region due to the Permian Acquisition. Total Badlands crude oil gathered increased due to system expansions. Badlands natural gas volumes were relatively flat primarily due to the impact of the severe winter weather in the first quarter of 2017.
The increase in operating expenses was primarily driven by the inclusion of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement in operations of the Raptor Plant at SouthTX.
Gross Operating Statistics Compared to Actual Reported
The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field portion of the Gathering and Processing segment:
|
| Three Months Ended September 30, 2017 |
| |||||||||||||
Operating statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (1),(2) |
| Gross Volume (3) |
|
| Ownership % |
|
| Net Volume (3) |
|
| Actual Reported |
| ||||
SAOU (4) |
|
| 324.6 |
|
|
| 100 | % |
|
| 324.6 |
|
|
| 324.6 |
|
WestTX (5) (6) |
|
| 834.5 |
|
|
| 73 | % |
|
| 607.5 |
|
|
| 607.5 |
|
Total Permian Midland |
|
| 1,159.1 |
|
|
|
|
|
|
| 932.1 |
|
|
| 932.1 |
|
Sand Hills (4) |
|
| 193.0 |
|
|
| 100 | % |
|
| 193.0 |
|
|
| 193.0 |
|
Versado (7) |
|
| 210.9 |
|
|
| 100 | % |
|
| 210.9 |
|
|
| 210.9 |
|
Total Permian Delaware |
|
| 403.9 |
|
|
|
|
|
|
| 403.9 |
|
|
| 403.9 |
|
Total Permian |
|
| 1,563.0 |
|
|
|
|
|
|
| 1,336.0 |
|
|
| 1,336.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
| 330.1 |
|
| Varies (8) (9) |
|
|
| 260.0 |
|
|
| 330.1 |
| |
North Texas |
|
| 261.8 |
|
|
| 100 | % |
|
| 261.8 |
|
|
| 261.8 |
|
SouthOK |
|
| 515.2 |
|
| Varies (10) |
|
|
| 412.1 |
|
|
| 515.2 |
| |
WestOK |
|
| 367.1 |
|
|
| 100 | % |
|
| 367.1 |
|
|
| 367.1 |
|
Total Central |
|
| 1,474.2 |
|
|
|
|
|
|
| 1,301.0 |
|
|
| 1,474.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (11) |
|
| 60.9 |
|
|
| 100 | % |
|
| 60.9 |
|
|
| 60.9 |
|
Total Field |
|
| 3,098.1 |
|
|
|
|
|
|
| 2,697.9 |
|
|
| 2,871.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU (4) |
|
| 38.7 |
|
|
| 100 | % |
|
| 38.7 |
|
|
| 38.7 |
|
WestTX (5) (6) |
|
| 115.5 |
|
|
| 73 | % |
|
| 84.1 |
|
|
| 84.1 |
|
Total Permian Midland |
|
| 154.2 |
|
|
|
|
|
|
| 122.8 |
|
|
| 122.8 |
|
Sand Hills (4) |
|
| 21.0 |
|
|
| 100 | % |
|
| 21.0 |
|
|
| 21.0 |
|
Versado (7) |
|
| 25.3 |
|
|
| 100 | % |
|
| 25.3 |
|
|
| 25.3 |
|
Total Permian Delaware |
|
| 46.3 |
|
|
|
|
|
|
| 46.3 |
|
|
| 46.3 |
|
Total Permian |
|
| 200.5 |
|
|
|
|
|
|
| 169.1 |
|
|
| 169.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
| 35.4 |
|
| Varies (8) (9) |
|
|
| 28.6 |
|
|
| 35.4 |
| |
North Texas |
|
| 29.3 |
|
|
| 100 | % |
|
| 29.3 |
|
|
| 29.3 |
|
SouthOK |
|
| 42.7 |
|
| Varies (10) |
|
|
| 34.6 |
|
|
| 42.7 |
| |
WestOK |
|
| 20.7 |
|
|
| 100 | % |
|
| 20.7 |
|
|
| 20.7 |
|
Total Central |
|
| 128.1 |
|
|
|
|
|
|
| 113.2 |
|
|
| 128.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands |
|
| 9.0 |
|
|
| 100 | % |
|
| 9.0 |
|
|
| 9.0 |
|
Total Field |
|
| 337.6 |
|
|
|
|
|
|
| 291.3 |
|
|
| 306.2 |
|
|
|
|
|
|
|
|
|
| owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials. |
|
|
|
|
| SouthTX includes the |
|
|
| SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants |
| Badlands natural gas inlet represents the total wellhead |
|
| Three Months Ended September 30, 2016 |
| |||||||||||||
Operating statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (1),(2) |
| Gross Volume (3) |
|
| Ownership % |
|
| Net Volume (3) |
|
| Actual Reported |
| ||||
SAOU |
|
| 262.5 |
|
|
| 100 | % |
|
| 262.5 |
|
|
| 262.5 |
|
WestTX (4) |
|
| 695.0 |
|
|
| 73 | % |
|
| 506.0 |
|
|
| 506.0 |
|
Total Permian Midland |
|
| 957.5 |
|
|
|
|
|
|
| 768.5 |
|
|
| 768.5 |
|
Sand Hills |
|
| 140.9 |
|
|
| 100 | % |
|
| 140.9 |
|
|
| 140.9 |
|
Versado (5) |
|
| 180.6 |
|
|
| 63 | % |
|
| 113.8 |
|
|
| 180.6 |
|
Total Permian Delaware |
|
| 321.5 |
|
|
|
|
|
|
| 254.7 |
|
|
| 321.5 |
|
Total Permian |
|
| 1,279.0 |
|
|
|
|
|
|
| 1,023.2 |
|
|
| 1,090.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
| 218.0 |
|
| Varies (6) |
|
|
| 205.6 |
|
|
| 218.0 |
| |
North Texas |
|
| 315.2 |
|
|
| 100 | % |
|
| 315.2 |
|
|
| 315.2 |
|
SouthOK |
|
| 469.8 |
|
| Varies (7) |
|
|
| 392.8 |
|
|
| 469.8 |
| |
WestOK |
|
| 434.4 |
|
|
| 100 | % |
|
| 434.4 |
|
|
| 434.4 |
|
Total Central |
|
| 1,437.4 |
|
|
|
|
|
|
| 1,348.0 |
|
|
| 1,437.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (8) |
|
| 53.8 |
|
|
| 100 | % |
|
| 53.8 |
|
|
| 53.8 |
|
Total Field |
|
| 2,770.2 |
|
|
|
|
|
|
| 2,425.0 |
|
|
| 2,581.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU |
|
| 32.8 |
|
|
| 100 | % |
|
| 32.8 |
|
|
| 32.8 |
|
WestTX (4) |
|
| 92.9 |
|
|
| 73 | % |
|
| 67.6 |
|
|
| 67.6 |
|
Total Permian Midland |
|
| 125.7 |
|
|
|
|
|
|
| 100.4 |
|
|
| 100.4 |
|
Sand Hills |
|
| 15.2 |
|
|
| 100 | % |
|
| 15.2 |
|
|
| 15.2 |
|
Versado (5) |
|
| 21.8 |
|
| �� | 63 | % |
|
| 13.7 |
|
|
| 21.8 |
|
Total Permian Delaware |
|
| 37.0 |
|
|
|
|
|
|
| 28.9 |
|
|
| 37.0 |
|
Total Permian |
|
| 162.7 |
|
|
|
|
|
|
| 129.3 |
|
|
| 137.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
| 20.9 |
|
| Varies (6) |
|
|
| 19.7 |
|
|
| 20.9 |
| |
North Texas |
|
| 36.2 |
|
|
| 100 | % |
|
| 36.2 |
|
|
| 36.2 |
|
SouthOK |
|
| 42.4 |
|
| Varies (7) |
|
|
| 39.1 |
|
|
| 42.4 |
| |
WestOK |
|
| 27.2 |
|
|
| 100 | % |
|
| 27.2 |
|
|
| 27.2 |
|
Total Central |
|
| 126.7 |
|
|
|
|
|
|
| 122.2 |
|
|
| 126.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands |
|
| 7.8 |
|
|
| 100 | % |
|
| 7.8 |
|
|
| 7.8 |
|
Total Field |
|
| 297.2 |
|
|
|
|
|
|
| 259.3 |
|
|
| 271.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10) | Natural gas and NGL sales statistics in 2020 include statistics related to new commercial arrangements effective in January 2020, which resulted in a change from net presentation as “Fees from midstream services” to gross presentation as “Sales of commodities” and “Product purchases”. This change in presentation did not result in an impact to our operating or gross margin. |
(11) | Average realized prices include the effect of realized commodity hedge gain/loss attributable to our equity volumes, previously shown in Other. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volumes as the denominator. |
The following table presents the realized commodity hedge gain/loss attributable to our equity volumes that are included in the gross margin of Gathering and Marketing SegmentProcessing segment:
|
| Three Months Ended September 30, |
|
|
|
|
|
| Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 vs. 2016 |
|
| 2017 |
|
| 2016 |
|
| 2017 vs. 2016 |
| ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (In millions) |
| ||||||||||||||||||||||||||||||||||||
Gross margin |
| $ |
| 180.0 |
|
| $ |
| 186.7 |
|
| $ |
| (6.7 | ) |
|
| (4 | %) |
| $ |
| 553.3 |
|
| $ |
| 594.6 |
|
| $ |
| (41.3 | ) |
|
| (7 | %) |
Operating expenses |
|
|
| 64.1 |
|
|
|
| 60.7 |
|
|
|
| 3.4 |
|
|
| 6 | % |
|
|
| 194.8 |
|
|
|
| 170.0 |
|
|
|
| 24.8 |
|
|
| 15 | % |
Operating margin |
| $ |
| 115.9 |
|
| $ |
| 126.0 |
|
| $ |
| (10.1 | ) |
|
| (8 | %) |
| $ |
| 358.5 |
|
| $ |
| 424.6 |
|
| $ |
| (66.1 | ) |
|
| (16 | %) |
Operating statistics MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fractionation volumes (2)(3) |
|
|
| 329.3 |
|
|
|
| 313.2 |
|
|
|
| 16.1 |
|
|
| 5 | % |
|
|
| 324.3 |
|
|
|
| 312.8 |
|
|
|
| 11.5 |
|
|
| 4 | % |
LSNG treating volumes (2) |
|
|
| 27.2 |
|
|
|
| 25.6 |
|
|
|
| 1.6 |
|
|
| 6 | % |
|
|
| 31.6 |
|
|
|
| 23.3 |
|
|
|
| 8.3 |
|
|
| 36 | % |
Benzene treating volumes (2) |
|
|
| 16.1 |
|
|
|
| 20.2 |
|
|
|
| (4.1 | ) |
|
| (20 | %) |
|
|
| 20.5 |
|
|
|
| 21.4 |
|
|
|
| (0.9 | ) |
|
| (4 | %) |
Export volumes, MBbl/d (4) |
|
|
| 154.5 |
|
|
|
| 156.7 |
|
|
|
| (2.2 | ) |
|
| (1 | %) |
|
|
| 175.5 |
|
|
|
| 173.0 |
|
|
|
| 2.5 |
|
|
| 1 | % |
NGL sales, MBbl/d |
|
|
| 463.4 |
|
|
|
| 452.4 |
|
|
|
| 11.0 |
|
|
| 2 | % |
|
|
| 468.1 |
|
|
|
| 466.3 |
|
|
|
| 1.8 |
|
|
| — |
|
Average realized prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL realized price, $/gal |
| $ |
| 0.67 |
|
| $ |
| 0.46 |
|
| $ |
| 0.21 |
|
|
| 46 | % |
| $ |
| 0.64 |
|
| $ |
| 0.45 |
|
| $ |
| 0.19 |
|
|
| 42 | % |
|
| Three Months Ended September 30, 2020 |
|
| Three Months Ended September 30, 2019 |
| ||||||||||||||||||
|
| (In millions, except volumetric data and price amounts) |
| |||||||||||||||||||||
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
| ||||||
Natural gas (BBtu) |
|
| 17.5 |
|
| $ | 0.20 |
|
| $ | 3.5 |
|
|
| 18.8 |
|
| $ | 1.07 |
|
| $ | 20.1 |
|
NGL (MMgal) |
|
| 126.4 |
|
|
| 0.08 |
|
|
| 10.5 |
|
|
| 110.0 |
|
|
| 0.17 |
|
|
| 18.5 |
|
Crude oil (MBbl) |
|
| 0.5 |
|
|
| 16.75 |
|
|
| 8.0 |
|
|
| 0.4 |
|
|
| (1.76 | ) |
|
| (0.7 | ) |
|
|
|
|
|
|
|
|
|
| $ | 22.0 |
|
|
|
|
|
|
|
|
|
| $ | 37.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, 2020 |
|
| Nine Months Ended September 30, 2019 |
| ||||||||||||||||||
|
| (In millions, except volumetric data and price amounts) |
| |||||||||||||||||||||
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
| ||||||
Natural gas (BBtu) |
|
| 50.6 |
|
| $ | 0.55 |
|
| $ | 27.7 |
|
|
| 47.0 |
|
| $ | 1.29 |
|
| $ | 60.6 |
|
NGL (MMgal) |
|
| 322.1 |
|
|
| 0.15 |
|
|
| 49.7 |
|
|
| 252.1 |
|
|
| 0.11 |
|
|
| 27.9 |
|
Crude oil (MBbl) |
|
| 1.4 |
|
|
| 19.72 |
|
|
| 27.7 |
|
|
| 1.1 |
|
|
| (2.28 | ) |
|
| (2.6 | ) |
|
|
|
|
|
|
|
|
|
| $ | 105.1 |
|
|
|
|
|
|
|
|
|
| $ | 85.9 |
|
(1) | The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction. |
Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019
Gathering and Processing segment gross margin contributions, attributable to higher system volumes and fee-based margin in the Permian region, were offset by lower volumes in the Central region and lower realized hedge gains. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.
Operating expenses were lower due to cost reduction measures that resulted in decreases in compensation and benefits, contract labor and chemicals, despite the addition of the Peregrine and Gateway processing facilities in the Permian.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
Gathering and Processing segment gross margin contributions, attributable to higher inlet volumes and fee-based margin in the Permian region and Badlands and higher realized hedge gains, were offset by lower commodity prices and lower Central region volumes. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.
Operating expenses were lower due to cost reduction measures that resulted in decreases in contract labor, chemicals and compression rentals and lower ad valorem taxes, despite the addition of the Peregrine and Gateway processing facilities in the Permian.
Logistics and Transportation Segment
|
| Three Months Ended September 30, |
|
|
|
|
|
| Nine Months Ended September 30, |
|
|
|
|
| ||||||||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
|
| 2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
| ||||||||||||||||||||
| (In millions, except operating statistics and price amounts) |
| ||||||||||||||||||||||||||||||||||||
Gross margin |
| $ |
| 362.0 |
|
| $ |
| 310.4 |
|
| $ |
| 51.6 |
|
|
| 17 | % |
| $ |
| 1,057.0 |
|
| $ |
| 792.4 |
|
| $ |
| 264.6 |
|
|
| 33 | % |
Operating expenses (1) |
|
|
| 81.6 |
|
|
|
| 81.5 |
|
|
|
| 0.1 |
|
|
| 0 | % |
|
|
| 251.0 |
|
|
|
| 227.4 |
|
|
|
| 23.6 |
|
|
| 10 | % |
Operating margin |
| $ |
| 280.4 |
|
| $ |
| 228.9 |
|
| $ |
| 51.5 |
|
|
| 22 | % |
| $ |
| 806.0 |
|
| $ |
| 565.0 |
|
| $ |
| 241.0 |
|
|
| 43 | % |
Operating statistics MBbl/d (2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fractionation volumes (3) |
|
|
| 589.5 |
|
|
|
| 508.8 |
|
|
|
| 80.7 |
|
|
| 16 | % |
|
|
| 598.0 |
|
|
|
| 492.8 |
|
|
|
| 105.2 |
|
|
| 21 | % |
Export volumes (4) |
|
|
| 308.5 |
|
|
|
| 239.2 |
|
|
|
| 69.3 |
|
|
| 29 | % |
|
|
| 277.2 |
|
|
|
| 228.1 |
|
|
|
| 49.1 |
|
|
| 22 | % |
Pipeline throughput (5) |
|
|
| 300.9 |
|
|
|
| 131.8 |
|
|
|
| 169.1 |
|
|
| 128 | % |
|
|
| 273.0 |
|
|
|
| 44.4 |
|
|
|
| 228.6 |
|
| NM |
| |
NGL sales |
|
|
| 724.1 |
|
|
|
| 672.1 |
|
|
|
| 52.0 |
|
|
| 8 | % |
|
|
| 721.6 |
|
|
|
| 620.9 |
|
|
|
| 100.7 |
|
|
| 16 | % |
(1) | Effective January 1, 2020, pursuant to amendments to contractual arrangements with our partners, our share of operating expenses associated with GCF, an investment in an unconsolidated affiliate, are included in operating expenses. |
(2) | Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the |
| Fractionation |
|
|
(4) | Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets. |
(5) | Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu. |
NM | Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful. |
Three Months Ended September 30, 20172020 Compared to Three Months Ended September 30, 20162019
The increase in Logistics and MarketingTransportation segment gross margin decreasedwas primarily due to lowerhigher NGL transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to higher volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation margin, higher marketing gains,volumes as a result of the commencement of operations of Train 7 in the first quarter of 2020 and higher terminaling and storage throughput.Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities. Marketing margin decreased primarily due to lower fees. LPG export volumes decreased due to the deferral to the fourth quarter of 2017 of 12.5 MBbl/d of export volumes due to the temporary closure of the Houston Ship Channel resulting from Hurricane Harvey. Fractionationless optimization margin increased due to higher system product gains, higher supply volume despite the deferral to the fourth quarter of 2017 of 29.3 MBbl/d of supply volumes due to the temporary operational issues related to Hurricane Harvey, and higher fees. Fractionation gross margin was partially impacted by the variable effects of lower fuel and power that are largely reflectedrealized in operating expenses (see footnote (2) above).our marketing businesses.
Operating expenses increased primarily due to higher labor, higher repairswere flat, despite the operations of a number of system expansions, including Grand Prix, additional incremental fractionation capacity and maintenance, partially offset by lowerexpansion of our LPG export capabilities. Lower fuel and power costs and cost reduction measures that is largely passed through.resulted in lower compensation and maintenance were offset by increased taxes primarily attributable to Grand Prix and the inclusion of our share of operating expenses associated with GCF.
Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019
The increase in Logistics and Transportation segment gross margin results for the nine months ended September 30, 2017 were impacted by the same factors as discussed above for the three months ended September 30, 2017, with the exception of fuel and power, which were higher. Additional factors were lower commercial transportation margin and lower domestic marketing margin. Commercial transportation margin decreased primarily due to lower barge activity. Domestic marketing margin decreased primarily due to lower terminal margins.
Operating expenses increasedwas primarily due to higher fuelNGL transportation and power which is largely passed through, higher labor associated with Train 5,fractionation margin and higher maintenance associated with unusual one-time eventsLPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to higher volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes as a result of the commencement of operations of Train 6 in the second quarter of 2019, Train 7 in the first quarter of 2017.2020 and Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities. Marketing margin decreased due to less optimization margin realized in our marketing businesses.
Operating expenses were higher primarily due to theinclusion of our share of operating expenses associated with GCF, increased costs attributable to our fractionation and LPG export expansions, higher taxes primarily attributable to Grand Prix and to additional incremental fractionation capacity, and higher maintenance primarily attributable to Grand Prix, partially offset by lower fuel and power costs.
Other
|
| Three Months Ended September 30, |
|
|
|
|
|
| Nine Months Ended September 30, |
|
|
|
|
|
| Three Months Ended September 30, |
|
|
|
|
|
| Nine Months Ended September 30, |
|
|
|
|
| ||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 vs. 2016 |
|
| 2017 |
|
| 2016 |
|
| 2017 vs. 2016 |
|
| 2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
|
| 2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
| ||||||||||||
|
| (In millions) |
|
| (In millions) |
|
| (In millions) |
| |||||||||||||||||||||||||||||||||||||||
Gross margin |
| $ | (1.0 | ) |
| $ | 11.2 |
|
| $ | (12.2 | ) |
| $ | 3.9 |
|
| $ | 56.9 |
|
| $ | (53.0 | ) |
| $ | 88.6 |
|
| $ | (101.2 | ) |
| $ | 189.8 |
|
| $ | 215.9 |
|
| $ | (101.1 | ) |
| $ | 317.0 |
|
Operating margin |
| $ | (1.0 | ) |
| $ | 11.2 |
|
| $ | (12.2 | ) |
| $ | 3.9 |
|
| $ | 56.9 |
|
| $ | (53.0 | ) |
| $ | 88.6 |
|
| $ | (101.2 | ) |
| $ | 189.8 |
|
| $ | 215.9 |
|
| $ | (101.1 | ) |
| $ | 317.0 |
|
Other contains the results (including any hedge ineffectiveness) of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin andactivity mark-to-market gain/gains/losses related to derivative contracts that were not designated as cash flow hedges. The primary purpose of our commodity risk management activities is to mitigate a portion of
the impact of commodity prices on our operating cash flow. We have entered into derivative instruments to hedge the commodity price associated with a portion of our expectedfuture commodity purchases and sales and natural gas NGLtransportation basis risk within our Logistics and condensate equity volumes in our Gathering and Processing Operations that result from percent of proceeds/liquids processing arrangements. Because we are essentially forward-selling a portionTransportation segment. See further details of our future plant equity volumes, these hedge positions will move favorablyrisk management program in periods of falling commodity prices“Item 3. – Quantitative and unfavorably in periods of rising commodity prices.Qualitative Disclosures About Market Risk.”
The following table provides a breakdown of the change in Other operating margin:
|
| Three Months Ended September 30, 2017 |
|
| Three Months Ended September 30, 2016 |
|
|
|
|
| ||||||||||||||||||
|
| (In millions, except volumetric data and price amounts) |
|
|
|
|
| |||||||||||||||||||||
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
|
| 2017 vs. 2016 |
| |||||||
Natural gas (BBtu) |
|
| 17.3 |
|
| $ | 0.23 |
|
| $ | 4.0 |
|
|
| 13.8 |
|
| $ | 0.37 |
|
| $ | 5.1 |
|
| $ | (1.1 | ) |
NGL (MMgal) |
|
| 74.8 |
|
|
| (0.09 | ) |
|
| (6.7 | ) |
|
| (7.2 | ) |
|
| (0.25 | ) |
|
| 1.8 |
|
|
| (8.5 | ) |
Crude oil (MBbl) |
|
| 0.4 |
|
|
| 6.29 |
|
|
| 2.3 |
|
|
| 0.3 |
|
|
| 14.40 |
|
|
| 4.7 |
|
|
| (2.4 | ) |
Non-hedge accounting (2) |
|
|
|
|
|
|
|
|
|
| (0.6 | ) |
|
|
|
|
|
|
|
|
|
| (0.1 | ) |
|
| (0.5 | ) |
Ineffectiveness (3) |
|
|
|
|
|
|
|
|
|
| - |
|
|
|
|
|
|
|
|
|
|
| (0.3 | ) |
|
| 0.3 |
|
|
|
|
|
|
|
|
|
|
| $ | (1.0 | ) |
|
|
|
|
|
|
|
|
| $ | 11.2 |
|
| $ | (12.2 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, 2017 |
|
| Nine Months Ended September 30, 2016 |
|
|
|
|
| ||||||||||||||||||
|
| (In millions, except volumetric data and price amounts) |
|
|
|
|
| |||||||||||||||||||||
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
|
| 2017 vs. 2016 |
| |||||||
Natural gas (BBtu) |
|
| 43.3 |
|
| $ | 0.15 |
|
| $ | 6.6 |
|
|
| 34.0 |
|
| $ | 0.94 |
|
| $ | 31.9 |
|
| $ | (25.3 | ) |
NGL (MMgal) |
|
| 177.5 |
|
|
| (0.04 | ) |
|
| (7.7 | ) |
|
| 20.2 |
|
|
| 0.34 |
|
|
| 6.9 |
|
|
| (14.6 | ) |
Crude oil (MBbl) |
|
| 0.9 |
|
|
| 6.29 |
|
|
| 5.8 |
|
|
| 0.8 |
|
|
| 20.02 |
|
|
| 16.2 |
|
|
| (10.4 | ) |
Non-hedge accounting (2) |
|
|
|
|
|
|
|
|
|
| (0.9 | ) |
|
|
|
|
|
|
|
|
|
| 2.5 |
|
|
| (3.4 | ) |
Ineffectiveness (3) |
|
|
|
|
|
|
|
|
|
| 0.1 |
|
|
|
|
|
|
|
|
|
|
| (0.6 | ) |
|
| 0.7 |
|
|
|
|
|
|
|
|
|
|
| $ | 3.9 |
|
|
|
|
|
|
|
|
|
| $ | 56.9 |
|
| $ | (53.0 | ) |
|
|
|
|
|
|
As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $1.4 million and $6.3 million for the three and nine months ended September 30, 2017 and $5.8 million and $20.9 million for the three and nine months ended September 30, 2016, related to these novated contracts. From the acquisition date through September 30, 2017, we have received total derivative settlements of $100.9 million. The remainder of the novated contracts will settle by the end of 2017. These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.
Liquidity and Capital Resources
As of September 30, 2017,2020, we had $103.9$248.0 million of “Cash and cash equivalents,” on our Consolidated Balance Sheets. We believe our cash position, our cash flows from operating activities and remaining borrowing capacity on our credit facilitiesfacility (discussed below in “Short-term Liquidity”), and our cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.
Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing or repaying our indebtedness, and meeting our collateral requirements, will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices weather and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments – Response to Current Market Conditions.”
Our main sources of liquidity and capital resources are internally generated cash flows from operations, contributions from TRC that are funded through TRC’s access to debt and equity markets, borrowings under the TRP Revolver and the Securitization Facility, and access to debt markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facility, cash investments, hedging abilities, customer performance risks and counterparty performance risks.
Short-term Liquidity
Our short-term liquidity as of October 31, 2017,November 2, 2020 was:
|
|
| October 31, 2017 |
|
|
| November 2, 2020 |
| ||
|
|
| (In millions) |
|
|
| (In millions) |
| ||
Cash on hand | Cash on hand |
| $ | 196.3 |
| Cash on hand |
| $ | 252.3 |
|
Total availability under the TRP Revolver | Total availability under the TRP Revolver |
|
| 1,600.0 |
| Total availability under the TRP Revolver |
|
| 2,200.0 |
|
Total availability under the Securitization Facility | Total availability under the Securitization Facility |
|
| 350.0 |
| Total availability under the Securitization Facility |
|
| 250.0 |
|
|
|
|
| 2,146.3 |
|
|
|
| 2,702.3 |
|
|
|
|
|
|
|
|
|
|
|
|
Less: | Outstanding borrowings under the TRP Revolver |
|
| — |
| Outstanding borrowings under the TRP Revolver |
|
| (600.0 | ) |
| Outstanding borrowings under the Securitization Facility |
|
| (270.0 | ) | Outstanding borrowings under the Securitization Facility |
|
| (250.0 | ) |
| Outstanding letters of credit under the TRP Revolver |
|
| (24.6 | ) | Outstanding letters of credit under the TRP Revolver |
|
| (37.5 | ) |
| Total liquidity |
| $ | 1,851.7 |
| Total liquidity |
| $ | 1,814.8 |
|
Other potential capital resources associated with our existing arrangements include:
• | Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein. The TRP Revolver matures on June 29, 2023. |
In the second quarter of 2020, we amended the Securitization Facility to request an additional $500decrease the facility size from $400.0 million in commitment increases underto $250.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the TRP Revolver, subjectfacility termination date to the terms therein. The TRP Revolver matures on October 7, 2020.April 21, 2021.
A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P. They also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable that are tied to commodity sales and purchases are relatively balanced, with receivables from NGL and natural gas customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (1)(i) our cash position; (2)(ii) liquids inventory levels and valuation, which we closely manage; (3)(iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (4)(vi) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth capital projects.
Our workingWorking capital exclusiveas of current debt obligations, September 30, 2020 increased $34.7$249.7 million fromcompared to December 31, 2016 to September 30, 2017. 2019. The major items contributing to this increase were the increase in inventory duewas primarily attributable to higher pricesinventory balances, lower current maturities of debt from payments on our Securitization Facility, and volumes, additional collateral posted with our futures broker due to an increase in commodity prices,lower payables for capital expenditures and greater cash on hand. This increase wasproduct purchases, partially offset by an increase in capital expenditure accruals driven primarily by the Permian activities, and a decrease in our net risk management working capital position due to changes in the forward prices of commodities. The increase of $253.4 million in current debt obligations was mainly due to the reclassification of the remaining 5% Notes due 2018 to short-term. These notes were redeemed on October 30, 2017.lower receivables resulting from lower commodity prices.
Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, contributions from TRC, borrowings available under the TRP Revolver and the Securitization Facility and proceeds from debt offerings, as well as joint ventures and/or asset sales, should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and quarterly cash distributions to Targa for at least the next twelve months.
Long-term financing consistsFinancing
In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”), which committed a maximum of long-term debt obligationsapproximately $960 million of capital to the DevCo JVs.
As of September 30, 2020, total contributions from Stonepeak to the DevCo JVs were $911.4 million. As of September 30, 2020, total contributions from funds managed by Blackstone Energy Partners (“Blackstone”) to the Grand Prix Joint Venture were $341.3 million. These contributions from Stonepeak and preferred units.Blackstone are included in noncontrolling interests.
From time to time, we issue long-term debt securities, which we refer to as senior notes. Our senior notes issued to date, generally have similar terms other than interest rates, maturity dates and redemption premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% plus accrued interest to the redemption date, and in some cases, a make-whole premium. As of September 30, 20172020, and December 31, 2016,2019, the aggregate principal amount outstanding of our senior notes and other various long-term debt obligations, (excluding current maturities)including unamortized premiums, debt issuance costs and non-current liabilities of finance leases, was $3,957.6$7,217.2 million and $4,206.8$7,005.2 million, respectively.In October 2017, we issued $750.0 million aggregate principal amount of 5% Senior Notes due 2028, with net proceeds of $744.4 million after costs, and redeemed our outstanding 5% Senior Notes due 2018 at face value plus accrued interest through the redemption date.
The majority of our long-term debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRP Revolver.Revolver and the Securitization Facility. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of September 30, 2017,2020, we dodid not have any interest rate hedges.
In 2019, we closed on the sale of a 45% interest in Targa Badlands to GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “GSO”) for $1.6 billion in cash. Growth capital of Targa Badlands after the sale is funded on a pro rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to GSO and Targa, with GSO having a priority right on such MQDs. Additionally, GSO’s capital contributions would have a liquidation preference upon a sale of Targa Badlands. Targa Badlands is a discrete entity and the assets and credit of Targa Badlands are not available to satisfy the debts and other obligations of Targa or its other subsidiaries. As of September 30, 2020, the contributions from GSO were $74.0 million.
On November 2, 2020, we redeemed the $559.6 million remaining balance of our 5 ¼% Senior Notes due 2023.
In the third quarter of 2020, we issued $1.0 billion of 4⅞% Senior Notes due 2031, resulting in net proceeds of $991.0 million. A portion of the net proceeds from the issuance were used to fund the Tender Offer and redemption payments for our 6¾% Notes, with the remainder used for repayment of borrowings under the TRP Revolver.
We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million and redeemed the remaining aggregate principal amount of the 6¾% Notes, which totaled $318.0 million. We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs.
Additionally, during the first half of 2020, we repurchased a portion of the outstanding senior notes on the open market, paying $239.8 million plus accrued interest to repurchase $303.3 million of the notes. The repurchases resulted in a $61.1 million net gain, which included the write-off of $2.4 million in related debt issuance costs. We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
To date, we do not believe our debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 105 - Debt Obligations to our consolidated financial statements. For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”
In October 2015, we completed an offering of 5,000,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.” Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum.
On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. If we do not (or a third party with our prior written consent does not) exercise this option, then the holders of the Preferred Units (“Preferred Unitholders”)Unitholders have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement.
Compliance with Debt Covenants
As of September 30, 2017,2020, we were in compliance with the covenants contained in our various debt agreements.
Cash Flow
Cash Flows from Operating Activities
Nine Months Ended September 30, |
|
|
|
|
| |||||
2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
| |||
(In millions) |
| |||||||||
$ | 1,054.9 |
|
| $ | 897.4 |
|
| $ | 157.5 |
|
The Consolidated Statementsprimary drivers of Cash Flows included in our historical consolidated financial statements employs the traditional indirect method of presenting cash flows from operating activities. Underactivities are (i) the indirect method, netcollection of cash from customers from the sale of NGLs, natural gas and other petroleum commodities, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil (iii) changes in payables and accruals related to major growth capital projects, and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.
Net cash provided by operating activities is derived by adjusting our net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct methodoperations increased in which the actual cash receipts and outlays comprising cash flow are presented.
The following table displays our operating cash flows using the direct method as a supplement to the presentation in our consolidated financial statements:
|
| Nine Months Ended September 30, |
|
|
|
|
| |||||
|
| 2017 |
|
| 2016 |
|
| 2017 vs. 2016 |
| |||
|
| (In millions) |
| |||||||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash received from customers |
| $ | 6,070.2 |
|
| $ | 4,584.7 |
|
| $ | 1,485.5 |
|
Cash received from (paid to) derivative counterparties |
|
| (50.9 | ) |
|
| 64.9 |
|
|
| (115.8 | ) |
Cash distributions from equity investments (1) |
|
| 8.4 |
|
|
| 1.8 |
|
|
| 6.6 |
|
Cash outlays for: |
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases |
|
| 4,838.2 |
|
|
| 3,394.2 |
|
|
| 1,444.0 |
|
Operating expenses |
|
| 433.7 |
|
|
| 380.9 |
|
|
| 52.8 |
|
General and administrative expense |
|
| 133.6 |
|
|
| 110.6 |
|
|
| 23.0 |
|
Interest paid, net of amounts capitalized (2) |
|
| 154.5 |
|
|
| 197.1 |
|
|
| (42.6 | ) |
Income taxes paid, net of refunds |
|
| (4.9 | ) |
|
| 1.2 |
|
|
| (6.1 | ) |
Other cash (receipts) payments |
|
| 9.4 |
|
|
| (1.3 | ) |
|
| 10.7 |
|
Net cash provided by operating activities |
| $ | 463.2 |
|
| $ | 568.7 |
|
| $ | (105.5 | ) |
|
|
|
|
Higher commodity prices were the primary contributor to increased cash collections and payments for product purchases in 20172020 compared to 2016. Cash received from derivative settlements was lower as commodity price spreads between the prices paid to counterparties and the fixed prices we received on those derivative contracts were lower in 2017 in comparison to 2016. Interest payments are lower this year largely due to lower average outstanding debt balances, offset by the timing of payments of interest on two new series of notes we issued in 2016. Cash payments for operating expenses and general and administrative expenses increased2019 primarily due to higher compensationoperating margin and benefits, contractor and other professional services, coupled withan increase in cash distributions received from unconsolidated affiliates, partially offset by an increase in interest payments as a result of higher utilities and higher maintenance. Other cash payments in 2017 were higher mainly due to transaction expenses associated with the Permian Acquisition in 2017.average borrowings.
Cash Flows from Investing Activities
Nine Months Ended September 30, | Nine Months Ended September 30, |
|
|
|
|
| Nine Months Ended September 30, |
|
|
|
|
| ||||||||
2017 |
|
| 2016 |
|
| 2017 vs. 2016 |
| |||||||||||||
2020 | 2020 |
|
| 2019 |
|
| 2020 vs. 2019 |
| ||||||||||||
(In millions) | (In millions) |
| (In millions) |
| ||||||||||||||||
$ | (1,457.5 | ) |
| $ | (422.0 | ) |
| $ | (1,035.5 | ) | (654.0 | ) |
| $ | (2,619.7 | ) |
| $ | 1,965.7 |
|
Cash used in investing activities increaseddecreased in 20172020 compared to 2016,2019, primarily due to lower outlays for property, plant and equipment of $1,630.7 million, resulting from the completion of construction of Grand Prix, Train 6, Train 7, and additional processing plants and associated infrastructure in the Permian Basin in 2019 and early 2020. The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude system and a $241.5 million decrease in our contributions to unconsolidated affiliates primarily due to the $570.8 million outlay for the cash portioncompletion of the Permian Acquisition consideration. Capital expenditures increased $441.6 million during 2017 reflecting the spending for major growth projects during 2017 and the acquisition of the Flag City Plant.GCX Pipeline in 2019.
Cash Flows from Financing Activities
| Nine Months Ended September 30, |
| ||||||||||||
| Nine Months Ended September 30, |
| 2020 |
|
| 2019 |
| |||||||
| 2017 |
|
| 2016 |
| (In millions) |
| |||||||
Source of Financing Activities, net | (In millions) |
|
|
|
|
|
|
|
| |||||
Distributions | $ | (346.8 | ) |
| $ | (921.5 | ) | |||||||
Contributions from (distributions to) noncontrolling interests |
| (277.3 | ) |
|
| 419.8 |
| |||||||
Debt, including financing costs |
| 130.1 |
|
|
| 823.7 |
| |||||||
Contributions from TRC and General Partner | $ | 1,620.0 |
|
| $ | 1,191.0 |
|
| 50.0 |
|
|
| 200.0 |
|
Distributions |
| (633.1 | ) |
|
| (542.9 | ) | |||||||
Debt, including financing costs |
| (4.6 | ) |
|
| (808.6 | ) | |||||||
Equity offerings, net of financing costs |
| - |
|
|
| (7.5 | ) | |||||||
Sale of ownership interests in subsidiaries |
| — |
|
|
| 1,619.7 |
| |||||||
Payment of contingent consideration |
| — |
|
|
| (317.1 | ) | |||||||
Other |
| 47.9 |
|
|
| 15.8 |
|
| — |
|
|
| (10.7 | ) |
Net cash provided by (used in) financing activities | $ | 1,030.2 |
|
| $ | (152.2 | ) | |||||||
Net cash provided by financing activities | $ | (444.0 | ) |
| $ | 1,813.9 |
|
In 2017,2020, net cash used in financing activities is primarily due to distributions to TRC, and net distributions to noncontrolling interests, partially offset by a net increase of debt outstanding and contributions from TRC and General Partner. Our distributions to noncontrolling interests are higher than our contributions from noncontrolling interests in 2020, primarily due to completion of major growth capital projects in 2019. Our debt outstanding increased primarily due to the issuance of the 4⅞% Senior Notes due 2031 that resulted in cash proceeds of $991.0 million, partially offset by repurchasing a portion of our outstanding senior notes through open market purchases and the Tender Offer and redemption payments for the 6¾% Notes for a total of $831.0 million.
In 2019, we realized a net source of cash from financing activities primarily due to contributions from TRCthe sale of ownership interests in Targa Badlands and General Partner, partially offset by aTrain 7, net reduction of debt borrowings and payments of distributions to TRC. We reduced net debt borrowings through
repayments of the TRP Revolver and redemption of our 6⅜% Senior Notes. In September 2017, we sold a 25% interest in the Grand Prix Joint Venture and received a total of $75.0 million in contributions from Blackstone.
In 2016, we incurred a net use of cash from financing activities primarily due to a net reductionincrease of debt outstanding and paymentnet contributions from noncontrolling interests. The result was partially offset by payments of distributions, to TRC,as well as the final contingent consideration payment associated with our 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin. The issuance of 6½% Senior Notes due 2027 and 6⅞% Senior Notes due January 2029, partially offset by the redemption of 4⅛% Senior Notes due November 2019 contributed to the net increase of debt outstanding. The contributions from TRCnoncontrolling interests were primarily from Stonepeak and our general partner. With the contributions from TRC, we repurchased a portion of our senior notes through open market repurchases generally at a discountBlackstone to par values and repaid a portion of the outstanding borrowings under the TRP Revolver.fund growth capital projects.
Distributions
As a result of the TRC/TRP Merger,
TRC is entitled to receive all available Partnership distributions after paymentpayments of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement, as to whether to distribute all available cash for any period. See Note 1 – Organization and Operations of the “Consolidated Financial Statements” included in this quarterly report.
The following table details the distributions declared and/or paid by us during the three and nine months ended September 30, 2017.2020:
Three Months Ended |
| Date Paid Or to Be Paid |
| Total Distributions |
|
| Distributions to Targa Resources Corp. |
| ||
September 30, 2017 |
| November 10, 2017 | $ |
| 225.4 |
| $ |
| 222.6 |
|
June 30, 2017 |
| August 10, 2017 |
|
| 225.4 |
|
|
| 222.6 |
|
March 31, 2017 |
| May 11, 2017 |
|
| 209.6 |
|
|
| 206.8 |
|
December 31, 2016 |
| February 10, 2017 |
|
| 198.1 |
|
|
| 195.3 |
|
Three Months Ended |
| Date Paid or To Be Paid |
| Total Distributions |
|
| Distributions to Targa Resources Corp. |
| ||
September 30, 2020 |
| November 13, 2020 | $ |
| 51.7 |
| $ |
| 48.9 |
|
June 30, 2020 |
| August 13, 2020 |
|
| 51.7 |
|
|
| 48.9 |
|
March 31, 2020 |
| May 13, 2020 |
|
| 53.1 |
|
|
| 50.3 |
|
December 31, 2019 |
| February 13, 2020 |
|
| 241.9 |
|
|
| 239.1 |
|
Preferred Units
Distributions on our Preferred Units are declared and paid monthly. As of September 30, 2017,2020, we have 5,000,000 Preferred Units outstanding. For the three and nine months ended September 30, 2017,2020, $2.8 million and $8.4 million of distributions were paid. We have accrued distributions to Series A Preferred Unitholders of $0.9 million for September, which were paid subsequently on October 16, 2017.15, 2020.
In October 2017,2020, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit. This distribution will be paid on November 15, 2017.
Capital Requirements
Our capital requirements relate to capital expenditures, which are classified as expansion expenditures (including business acquisitions), and maintenance expenditures. Expansion capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.16, 2020.
|
| Nine Months Ended September 30, |
| |||||
|
| 2017 |
|
| 2016 |
| ||
|
| (In millions) |
| |||||
Capital expenditures: |
|
|
|
|
|
|
|
|
Consideration for business acquisition |
| $ | 987.1 |
|
| $ | — |
|
Contingent consideration (1) |
|
| (416.3 | ) |
|
| — |
|
Business acquisition, net of cash acquired |
|
| 570.8 |
|
|
| — |
|
|
|
|
|
|
|
|
|
|
Expansion |
|
| 914.6 |
|
|
| 370.2 |
|
Maintenance |
|
| 73.1 |
|
|
| 56.3 |
|
Gross capital expenditures |
|
| 987.7 |
|
|
| 426.5 |
|
Transfers from materials and supplies inventory to property, plant and equipment |
|
| (2.8 | ) |
|
| (1.9 | ) |
Change in capital project payables and accruals |
|
| (118.3 | ) |
|
| 0.4 |
|
Cash outlays for capital projects |
|
| 866.6 |
|
|
| 425.0 |
|
|
|
|
|
|
|
|
|
|
Total |
| $ | 1,437.4 |
|
| $ | 425.0 |
|
Capital Expenditures
|
|
We currently estimate that we will invest approximately $1,320.0 million in net growth capital expenditures (exclusive of
The following table details cash outlays for business acquisitions) for announcedcapital projects in 2017. Given our objective of growth through expansions of existing assets, other internal growth projects, and acquisitions, we anticipate that over time that we will invest significant amounts of capital to grow and acquire assets. Future expansion capital expenditures may vary significantly based on investment opportunities. We continue to expect that 2017 net maintenance capital expenditures will be approximately $110.0 million.
Our expansion capital expenditures increased for the nine months ended September 30, 20172020 and 2019:
|
| Nine Months Ended September 30, |
| |||||
|
| 2020 |
|
| 2019 |
| ||
|
| (In millions) |
| |||||
Capital expenditures: |
|
|
|
|
|
|
|
|
Growth (1) |
| $ | 542.6 |
|
| $ | 2,203.4 |
|
Maintenance (2) |
|
| 67.7 |
|
|
| 101.5 |
|
Gross capital expenditures |
|
| 610.3 |
|
|
| 2,304.9 |
|
Transfers from materials and supplies inventory to property, plant and equipment |
|
| (1.9 | ) |
|
| (21.7 | ) |
Change in capital project payables and accruals, net |
|
| 194.7 |
|
|
| 150.6 |
|
Cash outlays for capital projects |
| $ | 803.1 |
|
| $ | 2,433.8 |
|
(1) | Growth capital expenditures, net of contributions from noncontrolling interests, were $518.0 million and $1,870.8 million for the nine months ended September 30, 2020 and 2019. Net contributions to investments in unconsolidated affiliates were $0.5 million and $75.4 million for the nine months ended September 30, 2020 and 2019. |
(2) | Maintenance capital expenditures, net of contributions from noncontrolling interests, were $66.1 million and $95.5 million for the nine months ended September 30, 2020 and 2019. |
We currently estimate that in 2020 we will invest approximately $700 million in growth capital expenditures, net of noncontrolling interests, and net contributions to investments in unconsolidated affiliates for announced projects. We expect that 2020 maintenance capital expenditures, net of noncontrolling interests, will be approximately $110 million.
Total growth capital expenditures were lower for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2016,2019, primarily due to lower spending related toon growth capital investments, as a significant portion of our major projects began full service in 2019, including Grand Prix, Train 6, and additional processing plants and associated infrastructure in the Permian Basin, the Grand Prix NGL pipeline and the Channelview Splitter, as well as the acquisition of the Flag City. The increase was partially offset by the impact of the substantial completion of the CBF Train 5 project in the second quarter of 2016. OurBasin. Total maintenance capital expenditures increasedwere lower for 2017the nine months ended September 30, 2020 as compared to 2016,the nine months ended September 30, 2019, primarily due to higher volumes processed on our system. timing of maintenance projects.
Off-Balance Sheet Arrangements
As of September 30, 2017,2020, there were $38.3$44.9 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our customers.
Risk Management
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all our commodity derivatives with major financial institutions or major oilenergy companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.
Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, equity volumes, NGL equity volumes and condensate equity volumes and, future commodity purchases and sales, and transportation basis risk through 2020.2025. Market conditions may also impact our ability to enter into future commodity derivative contracts.
Commodity Price Risk
A significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of natural gas and/or NGLscommodities as payment for services. The prices of natural gas, NGLs and NGLscrude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.
The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of September 30, 2017,2020, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, and (ii) future commodity purchases and sales in our Logistics and MarketingTransportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment by entering into derivative instruments. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the
volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.
When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The fair value of our natural gas and NGL hedges’ fair valueshedges are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.
A majority of these commodity price hedging transactionshedges are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in commodity prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.
We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas, and NGL or crude oil prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.
Our operating revenues increased (decreased) by net hedge adjustments on commodity derivative contracts of $(3.6) million and $7.5 million, during the three months ended September 30, 2017 and 2016, and $(4.9) million and $46.4 million, during the nine months ended September 30, 2017 and 2016, as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.
Our risk management position has moved from a net liability position of $53.3 million at December 31, 2016 to a net liability position of $63.4 million at September 30, 2017. The fixed prices we currently expect to receive on derivative contracts are below the aggregate forward prices for commodities related to those contracts, creating this net liability position.
As of September 30, 2017, we had the following derivative instruments that will settle during the years shown below:
Natural GAS
Instrument |
| Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Type | Index | $/MMBtu |
|
|
|
| MMBtu/d |
|
| Fair Value |
| |||||||||||||||
|
|
|
|
|
|
|
| 2017 |
|
| 2018 |
|
| 2019 |
|
| 2020 |
|
| (In millions) |
| |||||
Gathering & Processing |
| |||||||||||||||||||||||||
Swap | IF-Waha |
| 2.8740 |
|
|
|
|
| 103,600 |
|
|
| - |
|
|
| - |
|
|
| - |
|
| $ | 2.7 |
|
Swap | IF-Waha |
| 2.6470 |
|
|
|
|
| - |
|
|
| 93,600 |
|
|
| - |
|
|
| - |
|
|
| 4.0 |
|
Swap | IF-Waha |
| 2.6327 |
|
|
|
|
| - |
|
|
| - |
|
|
| 65,383 |
|
|
| - |
|
|
| 6.2 |
|
|
|
|
|
|
|
|
|
| 103,600 |
|
|
| 93,600 |
|
|
| 65,383 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | IF-PB |
| 2.6602 |
|
|
|
|
| 40,900 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 0.5 |
|
Swap | IF-PB |
| 2.4802 |
|
|
|
|
| - |
|
|
| 45,900 |
|
|
| - |
|
|
| - |
|
|
| 0.2 |
|
Swap | IF-PB |
| 2.3700 |
|
|
|
|
| - |
|
|
| - |
|
|
| 35,000 |
|
|
| - |
|
|
| 0.9 |
|
|
|
|
|
|
|
|
|
| 40,900 |
|
|
| 45,900 |
|
|
| 35,000 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | IF-PEPL |
| 2.6835 |
|
|
|
|
| 16,000 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 0.1 |
|
Swap | IF-PEPL |
| 2.6835 |
|
|
|
|
| - |
|
|
| 16,000 |
|
|
| - |
|
|
| - |
|
|
| 0.6 |
|
Swap | IF-PEPL |
| 2.6835 |
|
|
|
|
| - |
|
|
| - |
|
|
| 16,000 |
|
|
| - |
|
|
| 1.5 |
|
|
|
|
|
|
|
|
|
| 16,000 |
|
|
| 16,000 |
|
|
| 16,000 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | NG-NYMEX |
| 3.9900 |
|
|
|
|
| 9,783 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 0.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | IF-Waha |
| 3.0000 |
|
| 3.6700 |
|
| 7,500 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 0.3 |
|
Collar | IF-Waha |
| 3.2500 |
|
| 4.2000 |
|
| - |
|
|
| 1,849 |
|
|
| - |
|
|
| - |
|
|
| 0.3 |
|
|
|
|
|
|
|
|
|
| 7,500 |
|
|
| 1,849 |
|
|
| - |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | IF-PB |
| 2.8000 |
|
| 3.5000 |
|
| 15,400 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 0.4 |
|
Collar | IF-PB |
| 3.0000 |
|
| 3.6500 |
|
| - |
|
|
| 7,637 |
|
|
| - |
|
|
| - |
|
|
| 1.5 |
|
|
|
|
|
|
|
|
|
| 15,400 |
|
|
| 7,637 |
|
|
| - |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swap | EP-PERMIAN |
| (0.1444 | ) |
|
|
|
| 4,891 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 0.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swap | PEPL |
| (0.3308 | ) |
|
|
|
| 4,891 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 0.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & Processing total |
|
|
|
|
| 202,965 |
|
|
| 164,986 |
|
|
| 116,383 |
|
|
| 0 |
|
| $ | 20.2 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (1) |
| |||||||||||||||||||||||||
Swap | NG-NYMEX |
| (3.1680 | ) |
|
|
|
| (229 | ) |
|
| (173 | ) |
|
| (247 | ) |
|
| - |
|
| $ | (0.0 | ) |
Swap | IF-Waha |
| 3.0647 |
|
|
|
|
| (9,707 | ) |
|
| (4,227 | ) |
|
| - |
|
|
| - |
|
|
| (0.5 | ) |
Basis Swap | Various | Various |
|
|
|
|
| 82,418 |
|
|
| 15,726 |
|
|
| 12,500 |
|
|
| 10,445 |
|
|
| (1.3 | ) | |
Future | Various |
| 3.2640 |
|
|
|
|
| - |
|
|
| 1,103 |
|
|
| - |
|
|
| - |
|
|
| (0.0 | ) |
Other total |
|
|
|
|
| 72,482 |
|
|
| 12,429 |
|
|
| 12,253 |
|
|
| 10,445 |
|
| $ | (1.8 | ) | |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 18.4 |
|
|
|
Instrument |
| Price |
|
|
|
|
|
|
|
|
|
| ||||||||||
Type | Index | $/gal |
|
|
|
| Bbl/d |
|
| Fair Value |
| |||||||||||
|
|
|
|
|
|
|
| 2017 |
|
| 2018 |
|
| 2019 |
|
| (In millions) |
| ||||
Gathering & Processing |
| |||||||||||||||||||||
Swap | C2-OPIS-MB |
| 0.2778 |
|
|
|
|
| 6,030 |
|
|
| - |
|
|
| - |
|
| $ | 0.0 |
|
Swap | C2-OPIS-MB |
| 0.2816 |
|
|
|
|
| - |
|
|
| 4,118 |
|
|
| - |
|
|
| (0.4 | ) |
Swap | C2-OPIS-MB |
| 0.2951 |
|
|
|
|
| - |
|
|
| - |
|
|
| 3,460 |
|
|
| (1.0 | ) |
Total |
|
|
|
|
|
|
|
| 6,030 |
|
|
| 4,118 |
|
|
| 3,460 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | C3-OPIS-MB |
| 0.6598 |
|
|
|
|
| 10,382 |
|
|
| - |
|
|
| - |
|
|
| (9.7 | ) |
Swap | C3-OPIS-MB |
| 0.6274 |
|
|
|
|
| - |
|
|
| 5,510 |
|
|
| - |
|
|
| (8.5 | ) |
Swap | C3-OPIS-MB |
| 0.5530 |
|
|
|
|
| - |
|
|
| - |
|
|
| 2,650 |
|
|
| (3.8 | ) |
Total |
|
|
|
|
|
|
|
| 10,382 |
|
|
| 5,510 |
|
|
| 2,650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | IC4-OPIS-MB |
| 0.8570 |
|
|
|
|
| 1,400 |
|
|
| - |
|
|
| - |
|
|
| (1.1 | ) |
Swap | IC4-OPIS-MB |
| 0.8053 |
|
|
|
|
| - |
|
|
| 560 |
|
|
| - |
|
|
| (0.6 | ) |
Swap | IC4-OPIS-MB |
| 0.7133 |
|
|
|
|
| - |
|
|
| - |
|
|
| 170 |
|
|
| (0.2 | ) |
Total |
|
|
|
|
|
|
|
| 1,400 |
|
|
| 560 |
|
|
| 170 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | NC4-OPIS-MB |
| 0.8538 |
|
|
|
|
| 3,930 |
|
|
| - |
|
|
| - |
|
|
| (2.9 | ) |
Swap | NC4-OPIS-MB |
| 0.7969 |
|
|
|
|
| - |
|
|
| 1,530 |
|
|
| - |
|
|
| (1.4 | ) |
Swap | NC4-OPIS-MB |
| 0.6989 |
|
|
|
|
| - |
|
|
| - |
|
|
| 460 |
|
|
| (0.6 | ) |
Total |
|
|
|
|
|
|
|
| 3,930 |
|
|
| 1,530 |
|
|
| 460 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | C5-OPIS-MB |
| 1.0997 |
|
|
|
|
| 1,690 |
|
|
| - |
|
|
| - |
|
|
| (0.7 | ) |
Swap | C5-OPIS-MB |
| 1.0703 |
|
|
|
|
| - |
|
|
| 1,140 |
|
|
| - |
|
|
| (2.1 | ) |
Swap | C5-OPIS-MB |
| 1.0783 |
|
|
|
|
| - |
|
|
| - |
|
|
| 659 |
|
|
| (0.9 | ) |
Total |
|
|
|
|
|
|
|
| 1,690 |
|
|
| 1,140 |
|
|
| 659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | C2-OPIS-MB |
| 0.240 |
|
| 0.290 |
|
| 410 |
|
|
| - |
|
|
| - |
|
|
| (0.0 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | C3-OPIS-MB |
| 0.570 |
|
| 0.68625 |
|
| 380 |
|
|
| - |
|
|
| - |
|
|
| (0.3 | ) |
Collar | C3-OPIS-MB |
| 0.530 |
|
| 0.65000 |
|
| - |
|
|
| 900 |
|
|
| - |
|
|
| (1.7 | ) |
Total |
|
|
|
|
|
|
|
| 380 |
|
|
| 900 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | IC4-OPIS-MB |
| 0.650 |
|
| 0.840 |
|
| - |
|
|
| 110 |
|
|
| - |
|
|
| (0.2 | ) |
Collar | IC4-OPIS-MB |
| 0.640 |
|
| 0.800 |
|
| - |
|
|
| - |
|
|
| 110 |
|
|
| (0.2 | ) |
Total |
|
|
|
|
|
|
|
| - |
|
|
| 110 |
|
|
| 110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | NC4-OPIS-MB |
| 0.650 |
|
| 0.800 |
|
| - |
|
|
| 300 |
|
|
| - |
|
|
| (0.6 | ) |
Collar | NC4-OPIS-MB |
| 0.640 |
|
| 0.760 |
|
| - |
|
|
| - |
|
|
| 300 |
|
|
| (0.4 | ) |
Total |
|
|
|
|
|
|
|
| - |
|
|
| 300 |
|
|
| 300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | C5-OPIS-MB |
| 1.210 |
|
| 1.415 |
|
| 130 |
|
|
| - |
|
|
| - |
|
|
| 0.0 |
|
Collar | C5-OPIS-MB |
| 1.230 |
|
| 1.385 |
|
| - |
|
|
| 32 |
|
|
| - |
|
|
| 0.0 |
|
Total |
|
|
|
|
|
|
|
| 130 |
|
|
| 32 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & Processing total |
|
|
|
|
| 24,352 |
|
|
| 14,200 |
|
|
| 7,809 |
|
| $ | (37.3 | ) | |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (1)(2) |
| |||||||||||||||||||||
Future | C2-OPIS-MB |
| 0.2741 |
|
|
|
|
| 13,804 |
|
|
| - |
|
|
| - |
|
| $ | (0.1 | ) |
Future | C2-OPIS-MB |
| 0.3007 |
|
|
|
|
| - |
|
|
| 1,534 |
|
|
| - |
|
|
| 0.2 |
|
Future | C2-OPIS-MB |
| 0.3138 |
|
|
|
|
| - |
|
|
| - |
|
|
| 329 |
|
|
| (0.0 | ) |
Total |
|
|
|
|
|
|
|
| 13,804 |
|
|
| 1,534 |
|
|
| 329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future | C3-OPIS-MB |
| 0.6394 |
|
|
|
|
| 13,120 |
|
|
| - |
|
|
| - |
|
|
| (13.5 | ) |
Future | C3-OPIS-MB |
| 0.6074 |
|
|
|
|
| - |
|
|
| 2,918 |
|
|
| - |
|
|
| (15.3 | ) |
Total |
|
|
|
|
|
|
|
| 13,120 |
|
|
| 2,918 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Future | IC4-OPIS-MB |
| 0.7706 |
|
|
|
|
| 1,033 |
|
|
| - |
|
|
| - |
|
|
| (1.1 | ) |
Future | IC4-OPIS-MB |
| 0.7825 |
|
|
|
|
| - |
|
|
| 55 |
|
|
| - |
|
|
| (0.2 | ) |
Total |
|
|
|
|
|
|
|
| 1,033 |
|
|
| 55 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future | NC4-OPIS-MB |
| 0.8314 |
|
|
|
|
| 9,946 |
|
|
| - |
|
|
| - |
|
|
| (8.2 | ) |
Future | NC4-OPIS-MB |
| 0.8027 |
|
|
|
|
| - |
|
|
| 1,616 |
|
|
| - |
|
|
| (5.3 | ) |
Total |
|
|
|
|
|
|
|
| 9,946 |
|
|
| 1,616 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future | C5-OPIS-MB |
| 1.1285 |
|
|
|
|
| 978 |
|
|
| - |
|
|
| - |
|
|
| (0.3 | ) |
Future | C5-OPIS-MB |
| 1.0890 |
|
|
|
|
| - |
|
|
| 466 |
|
|
| - |
|
|
| (0.8 | ) |
Total |
|
|
|
|
|
|
|
| 978 |
|
|
| 466 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Option | C2-OPIS-MB |
| 0.2694 |
|
|
|
|
| 2,174 |
|
|
| - |
|
|
| - |
|
|
| 0.1 |
|
Option | C2-OPIS-MB |
| 0.2963 |
|
|
|
|
| - |
|
|
| 1,644 |
|
|
| - |
|
|
| 1.1 |
|
Total |
|
|
|
|
|
|
|
| 2,174 |
|
|
| 1,644 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other total |
|
|
|
|
| 41,055 |
|
|
| 8,233 |
|
|
| 329 |
|
| $ | (43.4 | ) | |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (80.7 | ) |
|
|
|
|
CONDENSATE
Instrument |
| Price |
|
|
|
|
|
|
|
|
|
| ||||||||||
Type | Index | $/Bbl |
|
|
|
| Bbl/d |
|
| Fair Value |
| |||||||||||
|
|
|
|
|
|
|
| 2017 |
|
| 2018 |
|
| 2019 |
|
| (In millions) |
| ||||
Gathering & Processing |
| |||||||||||||||||||||
Swap | WTI-NYMEX |
| 53.50 |
|
|
|
|
| 3,150 |
|
|
| - |
|
|
| - |
|
| $ | 0.4 |
|
Swap | WTI-NYMEX |
| 48.76 |
|
|
|
|
| - |
|
|
| 2,420 |
|
|
| - |
|
|
| (2.7 | ) |
Swap | WTI-NYMEX |
| 50.86 |
|
|
|
|
| - |
|
|
| - |
|
|
| 1,293 |
|
|
| (0.0 | ) |
|
|
|
|
|
|
|
|
| 3,150 |
|
|
| 2,420 |
|
|
| 1,293 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | WTI-NYMEX |
| 54.04 |
|
| 64.09 |
|
| 1,380 |
|
|
| - |
|
|
| - |
|
|
| 0.5 |
|
Collar | WTI-NYMEX |
| 49.76 |
|
| 58.50 |
|
| - |
|
|
| 691 |
|
|
| - |
|
|
| 0.4 |
|
Collar | WTI-NYMEX |
| 48.00 |
|
| 56.25 |
|
| - |
|
|
| - |
|
|
| 590 |
|
|
| 0.3 |
|
|
|
|
|
|
|
|
|
| 1,380 |
|
|
| 691 |
|
|
| 590 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
| 4,530 |
|
|
| 3,111 |
|
|
| 1,883 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (1.1 | ) |
These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls). For
To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not designated as cash flow hedges, these contracts are marked-to-market and recorded in revenues.
We account forreflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair values of our financial assetsderivative instruments are also influenced by changes in market volatility for option contracts and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputsdiscount rates used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We determine the present values.
The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative contracts utilizing a discounted cash flow modelinstruments as of September 30, 2020:
|
| Fair Value |
|
| Result of 10% Price Decrease |
|
| Result of 10% Price Increase |
| |||
Natural gas |
| $ | 7.8 |
|
| $ | 49.7 |
|
| $ | (33.6 | ) |
NGLs |
|
| (55.1 | ) |
|
| 11.0 |
|
|
| (121.2 | ) |
Crude oil |
|
| 31.7 |
|
|
| 45.4 |
|
|
| 18.0 |
|
Total |
| $ | (15.6 | ) |
| $ | 106.1 |
|
| $ | (136.8 | ) |
The table above contains all derivative instruments outstanding as of the stated date for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. For the contracts that have inputs from quoted prices, the classificationpurpose of these instruments is Level 2 within the fair value hierarchy. For those contractshedging commodity price risk, which we are unableexposed to obtain quoteddue to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.
Our operating revenues increased (decreased) by $109.2 million and $(61.8) million during the three months ended September 30, 2020 and 2019 and $337.3 million and $(7.7) million during the nine months ended September 30, 2020 and 2019, as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.
The estimated fair value of our risk management position has moved from a net liability position of $6.1 million at December 31, 2019 to a net liability position of $15.6 million at September 30, 2020. The fixed prices we currently expect to receive on derivative contracts are below the aggregate forward prices for at least 90% of the full term of the commodity contract, the valuations are classified as Level 3
within the fair value hierarchy. See Note 14 - Fair Value Measurements incommodities related to those contracts, creating this Quarterly Report for more information regarding classifications within the fair value hierarchy.net liability position.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the Securitization Facility. Additionally, on and after November 1, 2020, distributions on the Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus 7.71%. As of September 30, 2017,2020, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRP Revolver and the Securitization Facility, and distributions
owed on the Preferred Units, will also increase. As of September 30, 2017,2020, we had $708.1$350.0 million in outstanding variable rate borrowings under the TRP Revolver and the Securitization Facility. A hypothetical change of 100 basis points in the interest raterates of our variable interest rate debt and Preferred Units accumulating at an annual floating rate would impact our annual interest expense by $7.1 million.$3.5 million and Preferred Unit distributions by $1.3 million based on our September 30, 2020 debt balances.
Counterparty Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the International Swap Dealers Association agreements with all our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by $32.4$67.0 million as of September 30, 2017.2020. The range of losses attributable to our individual counterparties as of September 30, 2020 would be between $0.3$1.7 million and $8.2$16.9 million, depending on the counterparty in default.
Customer Credit Risk
We extend credit to customers and other parties in the normal course of business. We have an established policy and various procedures to manage our credit exposure, risk, including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.
We have an active credit management process, which is focused on controlling loss exposure due to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectibleOur allowance for doubtful accounts resulted in a 1% reduction of our third-party accounts receivablewas $0.1 million and $0.0 million as of September 30, 2017, our operating income would decrease by $7.1 million2020 and December 31, 2019. Changes in the year ofallowance for doubtful accounts were not material for the assessment.three and nine months ended September 30, 2020.
No customer comprised 10% or greater than our consolidated revenues during the three months ended September 30, 2020. During the nine months ended September 30, 2019, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 10% of our consolidated revenues.
During the three and nine months ended September 30, 2019, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 11% and 12% of our consolidated revenues.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2020, the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting that occurred during the quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.reporting, during our most recent fiscal quarter.
PART IIII – OTHEROTHER INFORMATION
On December 26, 2018, Vitol Americas Corp. (“Vitol”) filed a lawsuit in the 80th District Court of Harris County, Texas against Targa Channelview LLC, a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview and Noble Americas Corp. (the “Splitter Agreement”), which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.
On October 15, 2020, the District Court awarded Vitol $129 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company plans to contest the award and is preparing an appeal to the Court of Appeals in Houston, Texas.
Additional information required for this item is provided in Note 1611 – Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.
For an in-depth discussion of our risk factors, see “Part I—Item 1A. Risk Factors” of our Annual Report.Report in addition to the risk factors discussed below. All of these risks and uncertainties, including those risks discussed below, could adversely affect our business, financial condition and/or results of operations.
Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.
Our operations can be affected by the level of natural gas, NGL and crude oil prices and the relationship between these prices. The prices of crude oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. Our future cash flows may be materially adversely affected if we experience significant, prolonged price deterioration. The markets and prices for crude oil, natural gas and NGLs depend upon factors beyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:
• | the impact of seasonality and weather; |
• | general economic conditions and economic conditions impacting our primary markets; |
• | the economic conditions of our customers; |
• | the level of domestic crude oil and natural gas production and consumption; |
• | the availability of imported natural gas, liquefied natural gas, NGLs and crude oil; |
• | actions taken by major foreign oil and gas producing nations; |
• | the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs; |
• | the availability of domestic storage for crude oil; |
• | the availability and marketing of competitive fuels and/or feedstocks; |
• | the impact of energy conservation efforts; |
• | stockholder activism and activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil and natural gas; and |
• | the extent of governmental regulation and taxation, including those related to the prorationing of oil and gas production. |
Additionally, we have been and may continue to be adversely affected by the continued impact on global demand for commodities related to the COVID-19 pandemic. The COVID-19 pandemic has reduced economic activity and the related demand for energy commodities. These effects, combined with a period of increased production from major oil producing nations and decreasing availability of crude oil storage has contributed to lower commodity prices compared to historical levels in 2020 to date and is expected to continue to impact demand over the short-to-medium term.
Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. Under these arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”
As further discussed in Note 4 – Property, Plant and Equipment and Intangible Assets and Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations, the global decline in commodity prices due to both demand and supply disruptions was a significant contributing factor to the non-cash impairment charges totaling $2,442.8 million for the nine months ended September 30, 2020.
The widespread outbreak of the COVID-19 pandemic or any other public health crisis that impacts the global demand for commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.
We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition. For example, the recent global spread of COVID-19 has caused business disruption, including disruption to the oil and gas industry. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. The full extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for crude oil, natural gas and natural gas liquids (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations.
The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while we expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.
Refer to Note 4 – Property, Plant and Equipment and Intangible Assets and in Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Recent Sales of Unregistered Securities.
Not applicable.
Repurchase of Equity by Targa Resources Partners LP or Affiliated Purchasers.
Not applicable.
Item 3. Defaults Upon Senior Securities.
Not applicable.
Item 4. Mine Safety Disclosures.
Not applicable.
Not applicable.
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| The cover page from this Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, formatted in Inline XBRL |
* | Filed herewith |
** | Furnished herewith |
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| Targa Resources Partners LP
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